Pang, Wei (Sinopec Research Institute of Petroleum Engineering) | Ding, Shidong (Sinopec Research Institute of Petroleum Engineering) | Zhang, Thongyi (Sinopec Research Institute of Petroleum Engineering) | Xia, Wenwu (Harding Shelton Group) | Akkutlu, I. Yucel (Texas A&M University)
Shale gas reservoirs hold adsorbed gas in kerogen. Laboratory techniques have been developed to measure the gas amount in samples. However, adsorbed gas recovery is an unsettled issue. Complexity is mainly due to adsorbed phase having an unknown composition and density, and desorbing in a selective fashion. Kerogen nanopores bring in added complexity to the analysis due to confinement effects. Our objective is to predict gas composition in kerogen pores and measure desorption limit during pressure depletion.
A new molecular simulation method is developed to predict in-situ composition of natural gas in model kerogen pores using composition of produced fluid from a Chinese shale gas well. In essence, the method re-distributes the fluid composition back into kerogen pores at initial reservoir conditions. Then one-by-one the pores are blown down in small pressure steps while the compositional variation in the pores is monitored. The recovery is measured by comparing the residual hydrocarbon molecules at different pressure steps during the blow down. Density, viscosity, mean free path of the fluids in model kerogen pores are computed using the trajectories of the adsorbed and free molecules.
At initial reservoir conditions we found that the gas mixture in kerogen nanopores becomes heavier and more viscous as the pore size becomes smaller. These compositional effects become significantly more amplified during the pressure depletion. Consequently, we observe that the kerogen pores release only the lighter end of the initial natural gas mixture in the pores, not allowing desorption of the heavier mixtures in smaller pores. The predicted Knudsen number values indicate that the compositional evolution in kerogen with pore size and pressure does not allow flow regime change. For the Chinese shale gas well fluid composition, we predict that the pores smaller than 5 nm has limited gas recovery and the transport in the larger pores stays in the slip flow regime.
The paper presents results of recovery from kerogen using molecular simulation of fluids in nanopores. The results bring in new insights into our understanding of the natural gas production limits from kerogen. The results indicate that methane adsorption isotherms do not represent the true nature of multi-component gas desorption from shale samples.
Source rocks such as shale are highly heterogeneous consisting of organic matter and various inorganic minerals. Microscopic images suggest that microcracks serve as conduits of the released gas from organic nanopores. The permeability of the shale matrix is primarily attributed to the stress sensitive microcracks which would be highly influenced by the changes in fluid pressure. As the microcracks are depleted, more gas molecules desorb from the organic nanopores, which, in turn, could affect the fluid pressure in the microcracks. Linking the local properties in the organic nanopores to the microcracks for a better understanding of the coupling between them is necessary for an improved modeling. In this paper, a multiscale pore-network modeling approach is presented to describe the organic material-microcrack system and to investigate large-scale features of gas transport in shale.
A multiscale pore network model consisting of clusters of organic pore network and microcrack is built to investigate the shale gas transport at macroscopic scale. The organic part of the network model consists of nano-capillaries interconnected at nanopores and the network accounts for the adsorptive-convective-diffusive transport mechanisms that have been derived recently for a single capillary. This organic nanopore-network is hydraulically connected to a microcrack. Then, mass balance at each node in the new domain is solved along with the assumed boundary conditions. Using the information at the nodes, the total flow rate, and the pressure distribution in the system are obtained as a function of time. The results show that the fluid pressure in the microcrack is sensitive primarily to the content of the organic material and its permeability. An empirical formulation is developed to quantify this sensitivity. This relationship can be investigated in the laboratory and used in theoretical models in predicting the shale gas production.
Characterization studies of organic-rich shale oil reservoirs have revealed significant volumes of hydrocarbon fluids in kerogen. However, the recovery from kerogen pores is challenging due to amplified fluid-solid interactions. New methods can be developed for improved recovery targeting oil from kerogen pore space by modifying the forces of molecular interactions using chemical injection. A highly-developed kerogen pore-network is required for the penetration and delivery of chemical agents that are expected to function in the confined space, such surface active agents. Using advanced computational chemistry tools, the objective of this paper is to show that the maturation (the exposure to high temperature, high pressure) of kerogen during catagenesis relates to the quality of the kerogen pore network such as pore size and shape, and plays important role in the action of added chemicals in the EOR processes.
A new molecular dynamics simulation approach is developed applying dramatic changes to the organic chemicals system temperature to mimic varying degree of maturation. Simulation focuses on Type II kerogen, as it is the most common overall source of presently produced hydrocarbons. Two different chemical structures of type-II kerogen (C175H102N4O9S2, C242H219N5O12S2) are used as the building blocks to simulate the solid kerogen. The molar fractions of the elements are controlled to satisfy the overall H/C and O/C ratio of type-II kerogen in the oil window. The simulated hydrocarbon fluid consists of nine different types of molecules: dimethylnaphthalene, toluene, tetradecane, decane, octane, butane, propane, ethane and methane. The simulation box containing these molecules is subjected to a slow quenching process, which continues down to the reservoir temperature and pressure conditions. The effects of maximum temperature and the rate of quenching on the pore morphology of kerogen and the distribution of oil in the pore-network are discussed. We explain how kerogen pore morphology is controlled by the quenching rates. Next, we simulate the interaction of microemulsion droplets with the digital kerogen.
Results show that the microemulsion droplets posess elastic properties which allow them to squeeze through the kerogen pores smaller than the droplet's own diameter and to adsorb at pore wall surfaces. One major benefit associated with the use of microemulsions is the ability of the droplets to transport and deliver solvents and surfactants to different parts of the pore network. Our work shows that solvents and surfactants with particular features can be delivered in the form of a microemulsion droplet into oil saturated kerogen pore network and influence the oil mobility.
Much work has been done targeting hydrocarbon fluids in organic materials of source rocks such as kerogen and bitumen. These were, however, limited in scope to simple fluids confined in nanopores and ignored multi-component effects. Recent studies using hydrocarbon mixtures revealed that compositional variation caused by selective adsorption and nano-confinement significantly alters the fluids phase equilibrium properties. One important consequence of this behavior is capillary condensation and trapping of hydrocarbons in nanopores. Fluid expansion is not an effective mechanism in these pores. To show the impact of lean gas injection on the hydrocarbons recovery, an investigation is carried out using equilibrium molecular simulations of hydrocarbon mixtures with varying concentrations of CO2. The results with N2 are also presented for comparison. We show that large molecules in the mixture are left behind in nanopores are generally responsible for the residual hydrocarbon amount, and that high-pressure CO2 injection extracts more hydrocarbons from the nanopores than that based on pressure depletion only. In these small pores, the injection pressure and the kind of injected gas play a critical role in recovery. We also show that the nanopore surface area, rather than the nanopore size, is the primary factor affecting the residual amount. CO2 molecules introduced into the nanpores during the soaking period of a cyclic injection operation lead to exchange of molecules and a shift in the phase equilibrium properties of the confined fluids. This exchange has a stripping effect and in turn enhances the hydrocarbons recovery. However, the subsequent production and pressure depletion has no additional impact on the recovery beyond the stripping effect. CO2 injection and soaking has the ability to extract the heavier hydrocarbon fluids irrespective of the operating pressure conditions, while the pressure depletion produces the lighter fluids from the nanopores.
This paper describes the stress-dependent permeability of split shale core plugs from Eagle Ford, Bakken, and Barnett formation samples studied in presence of microproppants in microcracks. An analytical permeability model is developed, including the interaction between the fracture walls and monolayer microproppants under stress. The model is then used to analyze a series of pressure pulse decay measurements of the propped shale samples in the laboratory. The analysis provides the propped fracture permeability of the samples and predicts a parameter related to the quality of the proppant areal distribution in the fracture. The proppant placement quality can be used as a measure of success of the delivery of proppants into the fractures and to design stimulation in the laboratory.
Model development for organic materials such as kerogen and bitumen using molecular building blocks is an important and fast-evolving science for source rock characterization. However, the size of the current models is much smaller than the representative elementary volume of organic in order to describe the macroscopic quantities such as diffusion coefficents and permeability. In addition, pore size distribution of the current models is skewed towards the lower end such that the predicted quantities are inaccurate.
A new methodology is presented to build larger organic models to overcome the scale-dependence issue. A solid organic skeleton can be built using 3D tomographs which can be obtained from high-resolution microscopy such as TEM. The skeleton is populated with atoms distributed based on the organic matters maturity and elemental composition. As part of the new methodology to build larger organic model, we replace the atoms that make up the skeleton with an average representative atom whose bond length with the surrounding representative atoms is tuned to maintain the solid density and the structure of the skeleton unchanged. The average force field parameters are calculated based on kerogen's elemental composition. Permeability of this simplified organic model is measured using molecular dynamics simulation of steady-state fluid flow through the model pore-network.
When the transport simulation results of the simplified organic model are compared to its counterpart carrying exact molecular description, the simplified model is accurate for the calculations of permeability, tortuosity, and saturations and reduced the computational cost significantly. The simplified model can be applied to large samples and plugged into the existing digital rock workflows, to utilize meaningful pore connection information provided from tomograhy.
Akkutlu, I. Yucel (Texas A&M University) | Baek, Seunghwan (Texas A&M University) | Olorode, Olufemi M. (Texas A&M University) | Wei, Pang (Sinopec Research Institute of Petroleum Eng.) | Tongyi, Zhang (Sinopec Research Institute of Petroleum Eng.) | Shuang, Ai (Sinopec Research Institute of Petroleum Eng.)
Organic-rich shale formations consist of multi-scale pore structure, which includes pores with sizes down to nano-scale, contributing to the storage of hydrocarbons. In this paper, we show that the hydrocarbons in the formation partition into fluids with significantly varying physical properties across the nanopore size distribution of shale. This partitioning is a consequence of multi-component hydrocarbon mixture stored in nanopores showing a significant compositional variation with the pore size. The smaller the pore is, the heavier and the more viscous the hydrocarbon mixture becomes. During the production and pressure depletion, primarily the lighter hydrocarbons of the mixture are released from the nanopores. Hence, the composition of the remaining hydrocarbons inside the pores becomes progressively heavier. The viscosity and apparent molecular weight of the hydrocarbon mixture left behind increase significantly during the depletion. The kinetic mean-free path length of the mixture does not increase, however, as anticipated from the kinetic theory of gases. Further, the length may decrease drastically in small nanopores as an indication of capillary condensation and trapping of the hydrocarbon mixture. These effects significantly limit the release of hydrocarbons from nanopores, in particular those pores with sizes smaller than 10nm.
In the light of these microscopic scale observations, the concept of composition redistribution of the produced fluids is introduced and a new volumetric method is presented honoring the compositional variability in nanopores for an improved accuracy in predicting hydrocarbons in-place in presence of adsorption and nano-confinement effects. The method allows us to differentiate mobile bulk hydrocarbon fluids from the fluids under confinement effects and from the trapped hydrocarbon fluid dissolved in the organic material. Hence, it also reduces the uncertainties in predicting the reserve. The application of the method is presented using produced hydrocarbon fluid composition for dry gas and wet-gas formations and using reservoir flow simulation of production from a multi-stage fractured single horizontal well. We showed that liquids production is mainly due to flow of bulk fluid in large-pore volume.
A new-generation compositional reservoir-flow-simulation model is presented for gas-bearing organic-rich source rocks, including convective/diffusive mass-balance equations for each hydrocarbon component in the organic (kerogen), inorganic, and fracture continua. The model accounts for the presence of dispersed kerogen with sorbed-gas corrected dynamic porosity. The Maxwell-Stefan theory is used to predict pressure- and composition-dependence of molecular diffusion in the formation. The equations are discretized and solved numerically by use of the control-volume finite-element method (CVFEM).
The simulation is derived from a new multiscale conceptual flow model. We consider that kerogen is dispersed at a fine scale in the inorganic matrix and that it will be the discontinuous component of total porosity at the reservoir-simulation scale, which could be up to six orders of magnitude larger. A simple mass-balance equation is introduced to enable kerogen to transfer gas to the inorganic matrix that is collocated in the same gridblock. The convective/diffusive transport takes place between neighboring gridblocks only in the inorganic matrix.
The simulation results show that the multiscale nature of the rock is important and should not be ignored because this could result in an overestimation of the contribution of the discontinuous kerogen. We also observe that although adsorbed fluid could contribute significantly to storage in the shale formation, its contribution to production could be severely limited by the lack of kerogen continuity at the reservoir scale and by a low degree of coupling between the organic and inorganic pores. The contribution of the Maxwell-Stefan diffusion to the overall transport in the shale formation increases as the inorganic matrix permeability is reduced because of pressure decline during production.
Resource shales have low permeability matrix with nanoporous features. At nano scale
Molecular dynamics simulation is employed to simulate the behavior of a nanodroplet dispersion facing a solid surface. The model nanodroplets comprise swollen micelles of C12E7 nonionic surfactant with the d-limonene solvent solubilized in their cores. An oil-wet solid surface is modeled using graphite to represent hydrophobic kerogen in shale, and a water-wet solid surface is modeled using brucite to represent hydrophilic inorganic materials in shale. These surfaces are considered to have nanocapillaries with varying sizes, available for the microemulsion penetration experiment. Our results indicate that penetration into capillaries with sizes less than 10 nm is strongly influenced by the wettability of the solid surface. In the case of an oil-wet solid surface the droplets adsorb on the surfaces and hence impact the penetration ability. In the case of a water-wet surface, however, microemulsion droplets effectively penetrate into the nanocapillaries. The droplets are capable of penetrating into the capillaries that are smaller than their own size. In both of these two cases, the solubilized solvent and the surfactant are delivered into a tight nanocapillary network and come into contact with the
Recent studies on multi-phase fluids in nanoscale capillaries indicated that the capillary wall-fluid interactions could play a dominant role on the co-existence of the phases, which may change the fundamental properties of the fluids, such as density, viscosity, and interfacial tension, to become capillary size-dependent. At the extreme of the confinement, these properties become vague. This raises a serious question on the validity of Young-Laplace equation to predict capillary pressure in small pores and capillaries that the unconventional resources commonly exhibit. In this paper, using nonequilibrium molecular dynamics simulation of mercury injection into nanocapillaries, we investigated the nature of multi-phase fluids in small pores and re-visited the Young-Laplace equation.
Higher capillary pressure is predicted for the model nanocapillaries used in the simulations compared to that value obtained using the Young-Laplace equation. The capillary pressure shows a power-law dependence to the size of the capillary. This dependence yields up to 70% difference in the estimated capillary pressure value for those capillaries with a diameter less than 10 nanometers. Based on the observations we propose a modified Young-Laplace equation to use for mercury-air filled pore systems which are commonly used for pore size distribution measurements of resource shale. The work can be extended to other multi-phase systems, such as oil-gas, oil-water, and water-gas, to study the behavior of multi-phase flow in resource shale.