Induced seismicity caused by underground fluid injection occurs because of pore pressure changes that lead to stress changes in the reservoir and the surrounding formations. Despite that noticeable seismic events from fluid injection is very rare, proper assessment of possible seismic events is important. The objective of this study is to develop numerical models that simulate stress changes, fault slips, and ground floor movements induced by underground fluids injection.
The numerical analysis process presented in this work consists of three steps. First, stress changes around the reservoir due to fluid injection are analyzed using a FEM-BEM (Finite Element Method - Boundary Element Method) coupled model. Secondly, the stability of faults located near the reservoir is evaluated using the displacement discontinuity method. Thirdly, elastic waves caused by the fault slip is simulated using a FEM model where seismic response on the surface are calculated. A field case study is also presented to demonstrate the applicability of the numerical model developed in this work.
The numerical analysis results indicate that stress concentration occurs around a boundary between the basement and sandstone beneath the reservoir. This affects the stability of existing faults in this region. As a result, when the fault is slipped, seismicity may be triggered. It is assumed that the slip is caused by stress changes in the faulted region as well as a pore pressure change in the fault, which is caused by volumetric strain changes of the fluid in the fault. A field case study based on wastewater injection in the Southwestern region of the United States where injection induced seismicity events have been recently reported, is also performed in this work. In this case study, the variation of rock strength is considered one of important factors in induced seismicity events.
The novelty of our model is the ability to quantitatively assess the risk of induced seismicity due to wastewater injection, which can be also applied to other applications such as CCS and underground gas storages. Moreover, conducting risk assessment by these numerical models can improve safety of underground fluid injection operations.
Development of reliable models for hydrocarbon-in-place and water saturation estimation requires knowledge about wettability of mudrocks and the parameters (including rock properties and reservoir condition) affecting it. A significant volume fraction of organic-rich mudrocks is composed of kerogen. Therefore, wettability of kerogen affects the overall wettability of organic-rich mudrocks. The chemical composition and structure of kerogen varies with kerogen type and thermal maturity, which affects the surface properties of kerogen such as wettability. In a recent publication, we demonstrated using experimental techniques that kerogen could be water-wet at low thermal maturities and oil-wet at higher thermal maturities. However, the impacts of kerogen type and reservoir temperature/pressure conditions on kerogen and mudrock wettability is yet to be quantified. Therefore, the objectives of this paper include (i) quantifying the impacts of kerogen molecular structure and composition on water adsorption capacities, (ii) quantifying the impacts of reservoir pressure and temperature on water adsorption capacity of kerogen using molecular dynamics (MD) simulations.
In order to achieve the aforementioned objectives, we use a combination of molecular dynamics simulations and experimental work. The inputs to the molecular dynamics simulations include realistic models of kerogen, which are condensed to porous kerogen structures. Water molecules are filled in kerogen pore structure and MD simulation is performed. The outputs of the simulations include radial distribution function (RDF), and adsorption isotherms of water on kerogen for different kerogen types, thermal maturities, and temperature conditions. The adsorption processes are modelled for pressure and temperature conditions ranging from 0 to 35 MPa and 320 to 370 K, respectively. The outcomes of molecular dynamics simulations demonstrated that the water adsorption capacities of kerogen vary significantly with kerogen type, thermal maturity, and temperature and pressure conditions. The RDF results showed that the water adsorption capacity decreased from type I to type III kerogen. The water adsorption capacity of kerogen was found to increase by 128% with 38% increase in oxygen content. The increase in the adsorption capacity was attributed to the strong attraction between oxygen containing functional groups in kerogen and water. The adsorption isotherms of water and kerogen samples showed that the water adsorption capacity decreased by 0.19 mmol/g as the temperature increased from 320 K to 370 K. The average water adsorption capacity of kerogen was found to increase by 20% with increase in pressure by 34 MPa. The results obtained from molecular dynamics simulations were found to be in good agreement with experimental results. The results of this paper can be used to predict the adsorption capacities of any kerogen with the availability of geochemical information. This important property of kerogen is required for estimating kerogen wettability and can enhance understanding of fluid-flow mechanisms in organic-rich mudrocks.
This paper presents a description of the technology for numerical simulation of thermal gas treatment on Bazhenov formation, taking into account features of Bazhenov formation and thermal gas treatment and assumptions of the simulator.
First of all it is required to determine the following parameters: voidness (porosity), permeability, fracturing, free oil (initial oil saturation), TOC (Total Organic Carbon). And also it is important to establish dependence of the parameters on temperature and pressure. Then, the process of thermal gas treatment can be conditionally divided into several stages: Effective production of light oil from drainable (permeable) zones (miscible displacement in front of the combustion front) Involvement of zones of reservoir containing kerogen during to heat treatment (pyrolysis reaction) and liberation of light oil and gaseous hydrocarbons from "locked" zones of reservoir. Involvement of the initially non-drainable (impermeable) zones of reservoir, named matrix (doesn’t mean the same as in dual porosity/permeability system). Especially these zones are the greatest interest among reservoir engineers because it can contain huge reserves of hydrocarbons.
Effective production of light oil from drainable (permeable) zones (miscible displacement in front of the combustion front)
Involvement of zones of reservoir containing kerogen during to heat treatment (pyrolysis reaction) and liberation of light oil and gaseous hydrocarbons from "locked" zones of reservoir.
Involvement of the initially non-drainable (impermeable) zones of reservoir, named matrix (doesn’t mean the same as in dual porosity/permeability system). Especially these zones are the greatest interest among reservoir engineers because it can contain huge reserves of hydrocarbons.
As a result of the steps described above, a 2D model was created, a numerical realization of the key processes taking place during thermal gas treatment on Bazhenov formation was carried out. Further, the main zones characterizing the process were identified and a physical justification for the individual indicators was given. Calculations of variants involving the matrix in the drainage process were carried out.
The calculated technological effect over a 50-year period of thermal gas treatment on the model (involving the production from matrix) was about 50% of the additional oil production, relative to the thermal gas treatment variant without involvement of matrix.
According to the results of the work, an evaluation of the efficiency of wet combustion was carried out during thermal gas treatment. The results of the calculations clearly demonstrate the advantage of using wet combustion. It is as stimulation of production of reservoir oil, as of additional synthetic oil as a result of kerogen pyrolysis reaction.
Enayatpour, Saeid (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, TX, USA) | Thombare, Akshay (Metarock Laboratories, Houston, TX, USA) | Aldin, Munir (Metarock Laboratories, Houston, TX, USA) | van Oort, Eric (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, TX, USA)
Oil and gas wells produce hydrocarbons for a limited number of years, and at the end of their production life they need to be plugged and abandoned. This process has to be done in a safe and economic way. Creep deformation of shale rock in uncemented casing sections may simplify well abandonments considerably. Creep can close the annular gap between a shale formation and an uncemented section of a casing string, generating a barrier that prevents hydrocarbons from flowing to the surface on the annular side. Wells with such a "shale-as-a-barrier" generated by creep now only require abandonment plugs on the inside of the casing, without the need for installation of additional annular barriers. This may eliminate such operations as casing milling and casing pulling, thereby allowing e.g. offshore abandonments to be done rigless, at significantly reduced cost.
This paper presents the first results of an experimental investigation and numerical modeling study into the nature of the "shale-as-a-barrier" phenomenon. Specifically, we focus on laboratory and field scale numerical simulation of creep behavior of North Sea Lark shale rock for oil and gas well plug and abandonment purposes. In our Finite Element simulations of the shale creep phenomenon, we have used the time-hardening creep model, which assumes a non-linear relationship between creep strain and stress, temperature and time. The model parameters were obtained from a curve fit of laboratory experimental results conducted for a creeping shale. Then, using the experimentally-derived parameters, numerical simulation was performed for a laboratory scale model and result was validated against laboratory results. Once this validation had taken place, the model size was extended to the field scale for prediction of annular closure time and barrier formation. Simulations show a strong correlation between rock stiffness and annular gap closure time, as expected; hence, the success of any "shale-as-a-barrier" project is a distinct function of shale rock stiffness. Lowering near-wellbore stiffness artificially may accelerate annular barrier creation of slowly creeping shale formations.
Simões Maciel, Rodrigo (Federal University of Espírito Santo) | Ressel Pereira, Fábio de Assis (Federal University of Espírito Santo) | Fieni Fejoli, Rômulo (Federal University of Espírito Santo) | Leibsohn Martins, André (Petrobras) | Duarte Ferreira, Marcus Vinicius (Petrobras)
Petrobras has faced several challenges concerning inorganic scaling in the Pre-salt cluster. Scale prediction plays an important role on well completion selection and supporting to define better alternatives for chemical injection location. However, predicting scale in wellbores is traditionally performed based on thermodynamical equilibrium of the formation water under static conditions. This strategy leads to conservative results since it neglects hydrodynamics and kinetics of the scaling process. This paper proposes a new approach to predict scaling in downhole conditions. The study seeks to contribute on the comprehension of the effect of fluid flow and equipment geometry variation in the crystal deposition process in intelligent well completion equipment.
Such completion devices act in managing the fluid flow influx from different reservoirs or multiple zones of the same reservoir. Despite the positive aspects of this technology, some authors have been pointing out some problems associated with specific applications of these tools. The most common issues are related to the considerable pressure differential and the occurrence of calcium carbonate (CaCO3) scale. The pressure drop in this tool induces the flash liberation of CO2 from the aqueous solution. Consequently, the chemical equilibrium is displaced towards the direction of precipitation of CaCO3 in the flow stream. This paper proposes a new approach to predict scaling in downhole conditions and aims to quantitatively evaluate the calcium carbonate precipitation on the smart completion element internal surfaces. Computational Fluid Dynamics (CFD) along with discrete phase modeling (DPM) is employed to simulate the transport and adhesion of the calcium carbonate crystals on the device. The valves geometries consider the main features observed on the field according to different suppliers, accounting the different possibilities of completion geometries for Brazilian Pre-Salt environment.
The results showed the tendency of scale deposition pointing out hot spots in several different completion accessories at downhole conditions. A better understanding of the scale potential has influenced the decision-making process on the completion design and workover alternatives in the Pre-salt wellbores.
Abdelaziz, Aly (University of Toronto) | Ha, Johnson (University of Toronto) | Abul Khair, Hani (Petronas Sdn. Bhd.) | Adams, Matthew (Petronas Canada) | Tan, Chee Phuat (Petronas Sdn. Bhd.) | Musa, Ikhwanul Hafizi (Petronas Sdn. Bhd.) | Grasselli, Giovanni (University of Toronto)
The Montney Formation of the Western Canadian Sedimentary Basin has emerged as one of the most prolific unconventional resource plays in the North American unconventional space. The authors propose a novel method to better understand the failure mechanics associated with hydraulic fracturing through laboratory testing under true triaxial conditions. This adds essential fundamentals with respect to upscaled field hydraulic fracturing operations in the formation. A representative source rock block recovered from outcrop was prepared into a cube and hydraulically fractured in the laboratory under true triaxial stress conditions. Field outcrop mapping of this quarry has confirmed that samples collected are of the same geological time and spatially equivalent to the source rock (
The test was numerically modeled in three-dimensions using the hybrid finite-discrete element method (FDEM) with the mechanical properties input determined through a series of standard laboratory rock mechanics tests discussed within. Post-test μCT of the tested cube revealed a fracture trace, and scan contrast was enhanced by injecting the cube with 5% wt potassium iodide solution. Interestingly, the highest fluid pressure recorded is slightly higher than σ3 whilst the plane of failure is normal to the intermediate principal stress (σ2) direction, which is parallel to the bedding planes. The results of the mechanical tests and hydraulic fracturing under true triaxial stress conditions reveal the significance and dominance of the macroscopic features and material anisotropy in dictating the overall strength and fracture plane orientation. Features which were unaccounted for in classical reservoir mechanics and the numerical model simulation, resulted in higher than predicted fracture initiation and propagation pressures than the laboratory experiment. This laboratory test approach allows a convenient and flexible method to capture the influence of the reservoir stress regime and its interaction with the sample anisotropy. Coupled with numerical simulations that encompass such features, this framework can benefit the industry by reproducing typical behavior observed in the field; thus, enhancing, improving, and increasing the efficiency of hydrocarbon recovery.
Sabet, Nasser (University of Calgary) | Mohammadi, Mohammadjavad (University of Calgary) | Zirahi, Ali (University of Calgary) | Zirrahi, Mohsen (University of Calgary) | Hassanzadeh, Hassan (University of Calgary) | Abedi, Jalal (University of Calgary)
This work focuses on modeling the miscible viscous fingering in porous media accounting for asphaltene precipitation and deposition. The mass balance equations for solvent and asphaltene are defined, and the highly nonlinear system of equations is solved numerically through hybridization of compact finite difference and pseudo-spectral methods. We explain how asphaltene precipitation and the resulting formation damage influence the growth of viscous fingers.
To conduct our analysis, we use the experimental data for the amount of asphaltene precipitation at different solvent mass fractions and also oil viscosity at various asphaltene and solvent contents. This data is measured in our lab and is used as input for the nonlinear numerical simulations. For these simulations, the conventional finite difference schemes cannot be applied as they suffer from the excessive computational time and most importantly, numerical dispersion. Therefore, we employ hybrid techniques to benefit from the high accuracy of spectral methods and capture the nonlinear dynamics of fingerings on very fine grids.
Hydrocarbons such as light n-alkanes are widely used as diluents in the production and upgrading of heavy oils. The addition of a diluent to heavy oil or bitumen alters the chemical forces acting within the mixture, leading to the precipitation of asphaltenes. It is hypothesized that precipitation of asphaltene from oil changes the viscosity behavior of the mixture, influences the dynamics of viscous fingering, and therefore affects the oil recovery. Moreover, asphaltene deposition alters the porosity and permeability of the porous media and might modify the flow paths, leading to possible formation damage. Our results show that asphaltene precipitates are mostly accumulated in the contact interface between the solvent and oil. The major asphaltene deposition occurs along the growing fingers leading to permeability reductions up to 30% in the studied cases.
In this paper we describe how incorporating inter-well flow of gas tracers into a numerical simulation model of an oil producing field allowed us to improve the reservoir characterization. Gas tracers evidenced the lateral and vertical reservoir connectivity, identified preferential flow paths and eventually provided an additional tool for the dynamic history match.
The field produces light oil with the support of miscible gas injection, from a reservoir composed of two stacked fluvial sandstones units. To improve the reservoir characterization four inter-well gas tracer campaigns involving a total of 13 injector wells have been successfully completed. All these tracer injections have then been modeled at our full field numerical simulation model with the purpose of challenging the reservoir description in it. Input from this exercise have been later-on used during the construction of geomodels, benefiting from our improved reservoir knowledge.
The reservoir is composed of two units, Middle (M) and Upper (U), both deposited as laterally amalgamated fluvial channels. Both units appear as vertically separated by an impervious shale interval, only absent in 2 wells out of 30.
The shale interval was originally considered as a possible flow barrier by the earliest geological models. However, numerical simulation models were only able to replicate observed tracers arrivals when specific vertical connections existed between both units, indicating the shale interval was no as laterally continuous as formerly suspected.
History matching the tracers arrivals in the western field area was also helpful to reveal a fast gas breakthrough between wells which were aligned perpendicularly to the main channel orientation (NW-SE). This finding confirmed that this prevailing channel orientation was not the only responsible for a good reservoir communication, but also the lateral amalgamation (SW-NE) of channels was exerting a significant control in low sinuosity fluvial systems, as well as secondary flow directions in high sinuosity systems.
The improved reservoir characterization have been reflected in subsequent reservoir geological models and numerical simulators, avoiding misleading history matching solutions. Also, it is worth to note that this have had a direct impact on the gas injection strategy followed in the field.
Quite commonly interwell tracer flow is not fully incorporated into numerical simulators. This is a time consuming process, which, in addition to the conventional model uncertainties, requires sensitivities to the associated tracer parameters. This paper demonstrate through a real case how valuable this additional effort may result, and how it may improve the geological and dynamic understanding of our field.
The utilization of synergistic mixtures of nanoparticles (NPs) and surfactants for enhanced oil recovery (EOR) has drawn increasing scientific attention. In this study, a series of coarse-grained (CG) molecular dynamics (MD) models were built to study the behaviors of NPs and surfactants in the vicinity of the oil/water interface. Hydrophilic, hydrophobic, and amphiphilic NPs were constructed to investigate the effect of hydrophobicity on the ability of NPs in term of interfacial tension (IFT) reduction. The synergistic effect of surfactants and NPs were also studied.
Surfactants and amphiphilic NPs can both accumulate at the interface of oil and water, while hydrophilic and hydrophobic NPs stay in water or oil phase. The NPs with various ratios of hydrophobic to hydrophilic domains were investigated to determine the types of NPs that result in the most IFT reduction. The comparison of IFTs indicates that amphiphilic NPs has a better ability to assist surfactants in further reducing the interfacial tension. Meanwhile, surface modification and the presence of surfactants can prevent the aggregation of NPs.
These MD simulation results allow us to figure out the physical behavior of NPs and surfactants at the oil/water interfaces. Analysis of the results can further assist the NPs synthesis for surfactant and/or surfactant-nanoparticle EOR applications in unconventional reservoirs.
Enhanced Oil Recovery (EOR) is well known for its potential to produce residual oil after the primary and secondary oil recovery. The residual oil is trapped in the narrow throat due to high capillary pressure, which is influenced by rock wettability and oil/water interfacial tension (IFT) (Wu et al., 2008). Surfactants have been widely investigated and employed in the EOR process to reduce the IFT and to alter the wettability (Sheng et al. 2015; Kamal et al., 2017; Negin et al., 2017). However, during the surfactant flooding, surfactants can adsorb onto the rock surfaces. This may result in the reduction of their concentrations, which significantly reduce the efficiency of surfactants in practical applications. The high cost of surfactants also makes this potential loss a critical issue. Many researchers have focused their studies on reducing the adsorption of surfactants by adding various materials in the chemical formulations.
In most US unconventional resources development, operators usually first drill the parent wells to hold their leases, and then infill wells are drilled. A challenge raised from this process is the well-to-well interference or frac-hits. Fractures in infill wells have a tendency to propagate toward the depleted region induced by the pressure sink of the parent well, resulting in asymmetric fracture growth in infill wells and frac-hit with the parent well. One of the available mitigation methods is to inject water into the parent well to re-pressurize the depleted region. Though several papers have released positive results from their numerical studies, both negative and positive responses are reported from filed applications. This paper focused on identifying the mechanism and key factors controlling the effectiveness of the subsequent parent well water injection. A coupling reservoir geomechanical model was built to evaluate the pressure and stress change caused by the parent well production and subsequent parent well water injection. The reservoir and geomechanical models are prepared based on a dataset from Eagle Ford Shale. At desired time steps, pressure distribution from reservoir simulation is used to calculate the corresponding stress status.
In this numerical simulation study, both reservoir properties and operating conditions are considered. Considering the production loss during the parent well injection, the maximum injection time is set to be 1 month. The magnitude and orientation of horizontal principal stresses within and around the depleted region are used as a criterion to evaluate the effectiveness of subsequent parent well injection. A general observation is that between two adjacent fracture clusters, 3 regions could be identified whose behaviors are significantly different during production and injection. The subsequent water injection could only restore the pressure and stress in region 1, which is within 10 ft to the fractures. Region 2 is severely depleted but the injection of 1 month generates no improvement in this region due to the low matrix permeability. Region 3 might exist, where oil is not produced, but Shmin reduces and this reduction could not be restored through injection of 1 month. If the injection generates a relatively uniform pressure distribution, then SHmax angle change could be reduced to 0. We also observed that: (1) for our case, an injection pressure equal to the initial reservoir pressure is recommended. Using low injection pressure, Shmin is found out to be lowest in fractures, which may make infill well fractures tend to propagate into and hit the parent well fractures. However, if injection pressure is increased to larger than the initial reservoir pressure and smaller than the minimum horizontal stress, the improvement is insignificant; (2) Comparison between uniform and non-uniform hydraulic fracture geometries shows that hydraulic fracture geometry mainly affects the depletion region far away from the wellbore. i.e. along the long fracture tips. After injection, in the case with long uniform fractures, the Shmin value in long fracture tips is still lowest. (3) An SRV with high permeability significantly extends the depletion region. If the permeability is not large enough i.e. 0.01 mD, after injection of 1 month, the restored Shmin is about 1000 psi lower than the base case without SRV. (4) Using low bottomhole pressure in production, restored pressure and stress are about 500 psi lower than the base case; and due to the large pressure contrast between region 1 and region 2, the SHmax angle change could not be reduced. (5) In a reservoir with normal pressure, as the pressure change is not large, it is easier for the subsequent injection to take effect.
This paper provides significant insights into how to design a successful subsequent water injection process in a parent well, mitigate the negative effects of frac-hits, and maximize production of both parent and infill wells.