The development of shale assets has reached a point where operators face the challenge of infill drilling. The scope of this project is to investigate the impact of neighboring well pads on the performance of a newly developed well/pad. This paper highlights the differences in production performance of "old" pads versus "new" well and analyzes how the depletion history of the existing pads affects the performance of new well.
The study area covers two pads: Pad A and Pad B which have 10 and 12 wells respectively; these wells have been producing since 2016 from the dry gas region of Marcellus Shale in southwestern Pennsylvania. Pad A and Pad B are more than 9000 ft apart, and the region between these two pads has potential for future development. For this project, a 3-D reservoir simulation model that includes both pads was built and calibrated to match past performance of Pad A and Pad B. The calibrated simulation model then was utilized for developing new wells. The reservoir simulation model was used to perform a sensitivity analysis on reservoir characteristics and the impact of Pad A and Pad B's depletion history on the performance of new well(s). The workflow involves optimizing the well spacing of proposed well(s) with/without considering the depletion history.
Usually, with the very low permeability of shale reservoirs, the depletion history of neighboring wells is expected to affect the performance of newly developed wells. The new wells are considered as a different well pad, and their stimulated reservoir volume does not overlap with the Pad A and Pad B. However, the region average reservoir pressure is reduced due to the Pad A and Pad B production history. In most of shale reservoir numeral simulation studies, the reservoir is considered virgin. The average reservoir pressure potentially impacts the well spacing optimization workflow as well as the designing of an effective well completion job. In this study we compare two scenarios. One scenario considers the depletion history of neighboring well pads and the other one does not. The net present value optimization was done with and without considering the impact of depletion history.
This project studies the effects of neighboring well pads on production performance of newly developed pad. Compared to the interaction of parent/child well in a single well pad, multi-pad studies are rare primarily because of the high computational cost associated with a multi-pad numerical simulation analysis.
The basic idea behind this research is to propose a work flow to model gas flow in numerical simulators, which would take into consideration all the complexities of the multiple porosity systems that exist in shale matrix and the different dynamics of flow involved within them. The concept of a multi porosity system that is composed of the organic part (kerogen), inorganic matter and natural and hydraulic fractures is used here. Kerogen is very different from other shale components because of its highly porous nature, capability to adsorb gas and abundance of nano-pores on its surface.
Some theories had been forwarded for the physics involved with gas flow in shale on a micro scale level. However, when working with reservoir scale models, the details as described for porosity systems in micro scale models is lost. To overcome this problem, the idea of dynamic apparent permeability, which is a function of matrix pressure, is introduced in this work. It helps in up-scaling the particulars of the micro scale model to a reservoir one and aids in modelling Darcy flow, Fickian diffusion and transition flow in between the matrix and fractures.
Our assumptions are validated by working with the case of a multi-stage hydraulically fractured horizontal gas well producing from the Barnett shale formation. Exisiting simulation model for this well doesn't take into consideration the relevant flow phenomenon and is used as a base case. History matching after integrating diffusion and desorption, with 7 years of production data, into model reveals that considering these additional processes impacts the assumed SRV region - affecting its volume as well as its properties. This is a critical factor in optimizing completion design, to lower down the well cost for same or even greater production.
We summarize our findings from production forecasts that matrix contribution towards production is under estimated when relevant assumptions for shale are not modelled. This signifies the importance of better understating the transport phenomenon occurring in shale, which would enable us to have a greater insight to scrutinize production data and later to predict changes in production as completion methods are changed. Similarly, this can play a vital role in well spacing for effective field development. This means that a multi stage high density fracturing job might not optimize the well in terms of its value. Decreasing our expenditure on well completions, such that their design results in lower production rates at the initial time period along with lower decline rates, would enable us to produce these wells longer for the same recovery. This would enable us to push the production in future where oil and gas prices might be better.
With large scale production of gas from shale resources, large volumes of pore space have been vacated. Therefore, there is a large capacity for storage of carbon dioxide in these resources. Furthermore, due to the higher affinity of the organic matter to carbon dioxide compared to methane, injection of carbon dioxide can replace the adsorbed methane and therefore, enhances the recovery of natural gas. The objective for this work is to investigate the sorption (adsorption of carbon dioxide and desorption of methane) in carbon-based organic channels using Molecular Dynamics (MD) simulations.
In this study, adsorption isotherms of methane and carbon dioxide are compared by performing grand canonical Monte Carlo (GCMC) simulations in identical setups of carbon channels. Excess and absolute adsorption isotherms of these gases are plotted and compared. Furthermore, the surface selectivity of carbon dioxide over methane is computed to determine the competitive adsorption of these two gases. To simulate the displacement process, MD simulations of displacement of methane molecules with carbon dioxide molecules in presence and absence of pressure gradients are performed. The results are compared for different values of gas pressures and pressure gradients.
According to the results, adsorption capability of carbon dioxide is found to be higher than that of methane under the same pressure and temperature. The selectivity values of carbon dioxide over methane is found to be higher than the ones for pressure range of 100 to 200
Wang, Jing (China University of Petroleum) | Liu, Huiqing (China University of Petroleum) | Zhang, Hongling (China University of Petroleum) | Luo, Haishan (The University of Texas at Austin) | Cao, Fei (The University of Texas at Austin) | Jiao, Yuwei (CNPC RIPED) | Sepehrnoori, Kamy (The University of Texas at Austin)
Numerical simulation is important to understand and predict the development of oil and gas reservoirs. Existing commercial simulators, such as CMG, ECLIPSE and VIP, have been widely used in the past several decades for their robust performance in computing and scaling. In these reservoir simulators, the fluid flow models are based on Darcy's law or its extended form; the volume of the adsorbed phase or component is overlooked as well. While this is acceptable for conventional oil/gas reservoirs or chemical flooding reservoirs, the gas flow regimes such as slippage flow, transition flow, and molecular-free flow significantly is deviated from Darcy flow for shale gas reservoirs. Besides, a large portion of the gas is stored in the pore in the form of adsorbed gas. If the volume of the adsorbed gas is still overlooked, the volume of free gas and original gas in place (OGIP) will be seriously overestimated. For the above reasons, it is commonly thought that existing commercial simulators could not be ideally used to simulate the development of shale gas reservoirs. Hence, it is desirable to attain a feasible approach to correct the petro-physical properties of shale gas effectively within the commercial simulators, in order that one can use them to accurately simulate the development of shale gas reservoirs. In this paper, we first derived the correction formulas for the bulk porosity, free gas saturation, and connate water saturation used for correcting the disregarded volume of adsorbed gas in commercial simulators. Then, we derived the models of permeability and porosity multipliers in matrix considering gas adsorption/desorption, geomechanics, non-Darcy flow regimes, and diffusion of adsorbed layer. Finally, the above models were used to attain the corrected petro-physical properties for simulating gas production based on the practical properties of shale gas reservoirs using commercial simulators. The validation was performed by comparing the simulation results of commercial simulator with the published mechanism simulator using gas field data. The results show that the simulation results using commercial simulator achieve good agreement with the published mechanism simulator with the corrected petro-physical properties. The corrections of bulk porosity, connate water saturation, and free gas saturation are very essential. The correction formulas for these properties can largely decreases the error of OGIP and the calculated gas production. Both permeability and porosity multipliers are the functions of gas pressure, but they are not a monotone decreasing/increasing function. The gas production may be significantly overestimated or underestimated without consideration of these characteristics of shale gas in different fields. The contributions of different mechanisms are also demonstrated using the commercial simulator. This work can evently solve the issue that existing commercial simulators cannot accurately simulate shale gas production. The researchers can easily use these commercial simulators with these corrected formulas, which is a great progress for modeling the development of shale gas reservoir.
New imaging techniques have revealed that the pore networks of shale plays consist primarily of inorganic materials, organic matter and natural fractures. However, the flow mechanism through these multi-porosity systems is not well understood. In addition, liquid-rich shale (LRS) plays exhibit several other challenges to modeling and analysis, including abnormally flattened produced gas-oil ratio (GOR), complex phase behavior and heterogeneous rock properties, etc. In this paper, we report results of our investigations of multiphase flow in LRS plays including the impact of critical parameters related to fluids, rock, pore structure, rock-fluid and stimulation processes on well performance of these resources.
We have conducted comprehensive reservoir numerical studies using a new procedure to divide porous media into four different sub-media (porosity systems) with distinctive characteristics: inorganic material and organic matter in the shale matrix along with natural and hydraulic fractures. New correlations for modifying PVT properties in nano-pores have been used to incorporate the impact of nano-pore confinement on phase behavior in organic nano-pores. The impact of the stimulation process on the formation and creation of the stimulated reservoir volume (SRV) is incorporated into the simulation model by changing natural fracture permeability in varying degrees depending on the distance from the main hydraulic fracture. The impact of rock compaction on transfer properties is captured by using pressure-dependent permeability throughout the natural fractures. The current model gives us the capability to better analyze the complex pore network and the governing flow mechanisms in LRS reservoirs. Different relative permeabilities for organic matter and inorganic materials are employed in our model to account for high critical gas saturations. Our model can also handle various flow interactions between organic matter, inorganic materials and fractures.
We concluded that the connectivity between the four pore systems and relative permeability functions are the most important uncertainties that affect fluid flows. Our numerical model reproduced anomalous GOR's that have been observed in liquid-rich shale oil wells. The study showed that nano-pore confinement delayed development of two-phase flow. It did not have a significant effect on producing GOR behavior of low thermal maturity reservoirs while in high maturity reservoirs it causes the” flat” GOR's observed in early stages of production. Enhanced critical gas saturation delays mobilization of gas molecules in nano-pores and could extend non-intuitive GOR behavior further when reservoir pressure drops below the bubble point. We found that permeability reduction due to compaction has a significant impact on the performance of LRS wells and could change ultimate oil recovery by more than 5%. Simulation results revealed that hydrocarbon production from LRS reservoirs exhibits complex dynamics that are controlled by the pore network, thermal maturity level, volatility of the reservoir fluid and hydraulic fracturing. The study shows that for moderate-GOR oil reservoirs, the constant GOR duration is greater than that for highly volatile oil reservoirs, as well as in reservoirs with a greater percentage of organic matter pores.
This study explored several unique phenomena in LRS reservoirs and presents a new methodology to better for improved modeling LRS wells and to estimate ultimate recovery more accurately. The results can be used for reservoir development strategies. Our This methodology enables reservoir engineers to better understand the complicated physics in LRS reservoir performance and provide a working procedure to transfer micro-scale SEM imaging measurements to reservoir scale simulation models.
There is considerable and timely interest in oil and condensate production from liquid-rich regions, placing emphasis on the ability to predict the behavior of gas condensate bank developments and saturation dynamics in shale gas reservoirs. As the pressure in the near-wellbore region drops below the dew-point, liquid droplets are formed and tend to be trapped in small pores. It has been suggested that the injection of CO2 into shale gas reservoirs can be a feasible option to enhance recovery of natural gas and valuable condensate oil, while at the same time sequestering CO2 underground. This work develops simulation capabilities to understand and predict complex transport processes and phase behavior in these reservoirs for efficient and environmentally friendly production management.
Although liquid-rich shale plays are economically producible, existing simulation techniques fail to include many of the production phenomena associated with the fluid system that consists of multiple gas species or phases. In this work, we develop a multicomponent compositional simulator for the modeling of gas-condensate shale reservoirs with complex fracture systems. Related storage and transport mechanisms such as multicomponent apparent permeability (MAP), sorption and molecular diffusion are considered. In order to accurately capture the complicated phase behavior of the multiphase fluids, an equation of State (EOS) based phase package is incorporated into the simulator. Due to the large capillary pressure that exists in the nanopores of ultra-tight shale matrix, the phase package considers the effect of capillary pressure on phase equilibrium calculations. A modified negative-flash algorithm that combines Newton's method and successive substitution iteration (SSI) is used for phase stability analysis under the effect of capillary pressure between oil and gas phases.
In addition, a lower-dimensional discrete fracture and matrix (DFM) model is implemented. The DFM model is based on unstructured gridding, and can accurately and efficiently handle the non-ideal geometries of hydraulic fracture in stimulated unconventional formation. Optimized local grid refinement (LGR) is employed to capture the extremely sharp potential gradient and saturation dynamics in the ultra-tight matrix around fracture.
We apply the developed simulator to study the combined effects of capillary pressure and multicomponent storage and transport mechanisms that are closely associated with the phase behavior and hydrocarbon recovery in gas-condensate shale reservoirs. We present preliminary simulation studies to show the applicability of CO2 huff-n-puff for the purpose of enhanced hydrocarbons recovery. Several design components such as the number of cycles and the length of injection period in the huff-n-puff process are also briefly investigated.
Wang, Jing (China University of Petroleum, Beijing) | Luo, Haishan (The University of Texas at Austin) | Liu, Huiqing (China University of Petroleum, Beijing) | Ji, Yuchen (Beijing Institute of Technology) | Cao, Fei (The University of Texas at Austin) | Li, Zhitao (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
Gas in shale gas reservoirs is stored by two mechanisms: free gas and adsorbed gas. The volume occupied by adsorbed gas is overlooked by current industry standards and numerical modeling. Also, stress dependence effect of matrix does not draw as much attention as hydraulic fractures. These two effects significantly impact Original Gas in Place (OGIP), gas flow regimes, and petro-physical properties during gas production. Therefore, development of an improved model and simulator with consideration of the volume consumed by adsorbed gas and the stress dependence effect of matrix is critical. In this paper, we develop a coupled model system for shale gas reservoir simulation. The equations considering the impact of gas adsorption/desorption upon effective porosity and permeability are derived and incorporated into the simulator. In particular, both Langmuir and BET (Brunauer, Emmett, and Teller) isotherms are incorporated using a unified formula. The stress dependence effect of matrix is included as well, which also affects effective porosity and permeability by decreasing the pore size. Subsequently, we demonstrate the numerical implementation of the mathematical model followed by the validation of our model using both experimental data and production data of shale gas fields. Finally, we discuss the dynamic changes of gas flow regimes, apparent permeability, and effective porosity during gas production using the new simulator. The results show that the model can predict the OGIP more accurately than the other models in the literature. In addition, we observe the dynamic changes of effective porosity, apparent permeability and gas flow regimes during gas production. Since gas desorption and stress dependence effect change the effective flow radius, they affect the absolute permeability directly, and further affect apparent permeability indirectly through increasing/decreasing the Knudsen number. The impacts of gas desorption and stress dependence effect on absolute permeability and Knudsen number are usually converse. Commonly, the gas flow regime belongs to slip and transition flows in shale gas reservoirs. In some cases, molecular-free regime (Knudsen diffusion) may appear. This work improves the simulation of gas production in shale gas reservoirs and makes a significant progress of numerical simulation of shale gas reservoirs.
Umeda, Kazuki (Kyoto U.) | Li, Rongjuan (Kyoto U.) | Sawa, Yunosuke (Kyoto U.) | Yamabe, Hirotatsu (Kyoto U.) | Liang, Yunfeng (Kyoto U.) | Honda, Hiromi (Kyoto U.) | Murata, Sumihiko (Kyoto U.) | Matsuoka, Toshifumi (Kyoto U.) | Akai, Takashi (JOGMEC) | Takagi, Sunao (JOGMEC)
Advanced microscopy and image analysis techniques revealed that massive nanpores exist in shale gas formations. The process of the microscopic gas transportation from nanpore systems (of shale) and the macroscopic produciton from shale gas reservoirs needs to be better understood. Here, we developed a multiscale simulation scheme for studying gas flow in nanpore systems using molecular dynamics (MD) and lattice Boltzmann method (LBM). MD is a powerful technique by which we can get thermodynamic properties of the simulation system at desired temperature and pressure, and simulate the gas flow in molecular scale. By this computational method, we will investigate transportation characteristics of methane molecule in molecular scale and estimate the slip velocities fordifferent solids at different temperatures and pressures. LBM, on the other hand, is a computational method for continuous fluid dynamics. In enables us to upscale MD simulation results from molecular scale to pore-scale with complicated geometries, and estimates the permeability to taking consideration of the slip velocities.
First, we calculated the mean free path and slip velocity, and evaluated the slip velocity as a function of Knudsen number using MD simulations. The MD simulations were conducted for three different constituents of shale nanpore surfaces; quartz, clay and kerogen at around 12 MPa and temperatore from300 K to 400 K. The fully hydroxlated α-quartz (001) surface, which contains vicinal silanol, was employed as a model of quartz system. The uncharged pyrophyllite surface was employed to represent a model of clay. The shinn model (Type III) kerogen slab was employed as a model of organic rich shale.
Second, we implemented the slip velocity obtained from MD simulations in LBM simulations. As for the fluid-solid boundary, we adopted counter slip boundary condition, which enables us to configure the slip velocity at the wall so as to satisfy that obtained from MD simulations. Then, we simulated the gas flow in nanpores with different pore geometries. For a simple slit geometry, it was found that the slip flow induced high permeability, which is about 0.1-1.8 times of that for non-slip flow. For systems with complicated geometries, we demonstrated that permeability of slip flow can be estimated from the pore profile. The application of multiscale simulation scheme to a more realistic system is straightforward.
Vertical and horizontal inter-well communication in unconventional reservoirs remains a major uncertainty. This paper presents the results of geochemical analyses performed on several wells in the Bakken and Three Forks unconventional oil reservoirs. Geochemical analyses performed on oil extracted from core, oil sampled while drilling, and oil produced after stimulation indicate that the geochemical signatures of the Bakken and Three Forks Formations are different and unique to its respective stratigraphic units. Using unique geochemical signatures, this study developed a procedure for identifying the production of mixed oils and the relative contribution from each contributing startigraphic units.
To further investigate vertical communication a detailed geologic model was constructed using core and outcrop data. The model was simulated and history matched to estimate contribution from adjacent layers. Various scenarios were simulated to understand the probability of communication. Analyses suggest that vertically adjacent layers contribute to production as predicted by the reservoir model and measured by the geochemical signature of the oil.
This paper demonstrates (a) contribution from vertically adjacent formations can be significant, (b) geochemistry may be utilized to quantify vertical drainage, and (c) quantification of contribution from offset layers helped to constrain a reservoir simulation history match. Results from this study have facilitated the assessment of the degree of vertical communication across various flow units, which is the key to an efficient reservoir development.