PRISM :: Browsing by Author "Aguilera, Roberto"

Browsing by Author "Aguilera, Roberto"

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Open Access
3D Modeling of Fracturing and Refracturing in Unconventional Reservoirs
(2019-09-20) Urban Rascón, Edgar; Aguilera, Roberto; Aguilera, Roberto; Kantzas, Apostolos K.; Moore, Robert Gordon Gord; Mehta, Sudarshan A. Raj; Lines, Larry R.; Camacho, Rodolfo C. V.
Unconventional gas reservoirs considered in this thesis include low and ultralow permeability shales and tight reservoirs. Gas production from unconventional reservoirs has grown dramatically in the United States during the last decade and has helped that country to become a top gas producer around the world. Extensive use of natural gas has in turn reduced CO2 emissions to levels not seen in the United States since the 1990s. This has happened due to innovations associated with two main technologies: (1) Drilling of horizontal wells and (2) multistage hydraulic fracturing. This success in the United States has inspired the primary objective of this thesis: Finding means of improving gas rates and recoveries by fracturing and refracturing unconventional reservoirs. To this end, the thesis presents the development of an original 3D fracture propagation model that helps to understand hydraulic fractures and their growth in unconventional reservoirs. Results from the 3D fracture propagation model are calibrated with microseismic data and are used in (1) an original hybrid hydraulic fracture (HHF) simulation model for estimating stimulated reservoir volume (SRV), (2) reservoir modeling with a fully coupled HHF-geomechanics model, and (3) a comparison of refracturing vs. infill drilling. The thesis closes with an evaluation that discusses the economic aspects of refracturing. It is concluded that the fracture propagation model developed in this thesis provides valuable information regarding fracturing and refracturing of unconventional reservoirs. Furthermore, it generates useful input data for fluid flow simulations, and improvements in production rates and recoveries of natural gas from unconventional tight and shale reservoirs.
Open Access
A New Material Balance Methodology for Quintuple Porosity Shale Gas and Shale Condensate Reservoirs
(2016) Orozco Ibarra, Daniel Ricardo; Aguilera, Roberto; Chen, Zhangxing (John); Kantzas, Apostolos
A recent petrophysical formulation states that all the storage mechanisms present in shale reservoirs are best represented by a quintuple porosity system that is further fed by dissolved gas in the solid kerogen. The quintuple porosity system is made up of: 1) adsorbed gas in the pore walls of the organic matter, 2) free gas stored in the inorganic matrix porosity, 3) free gas stored in natural fractures (microfractures and slot porosity), 4) free gas stored in the hydraulic fractures created around the wellbore by the stimulation job, and 5) free gas stored in the organic nanopores. This thesis presents a new material balance methodology for shale gas and shale condensate reservoirs that considers all the aforementioned storage mechanisms. Results lead to the conclusion that ignoring the effects of gas diffusion from kerogen in shale material balance calculations can lead to pessimistic estimates of both OGIP and production forecasts.
Open Access
A New Method For Production Data Analysis Using Superposition-Rate
(2015-12-10) Liang, Yue; Aguilera, Roberto; Mattar, Louis; Harding, Thomas; Moore, Robert; Hugo, Ronald
This research presents a new method to analyze production data – the superposition-rate. The method was developed based on the well-accepted superposition principle. It is presented in a generalized form and is applicable to data in transient flow (including radial, linear, and bilinear flow) as well as in boundary dominated flow. The superposition-rate method is validated by synthetic data generated from reservoir modeling. Moreover, a simple yet practical workflow of implementing the superposition-rate in production data analysis is presented. Last, real field examples are utilized to demonstrate the practicality of superposition-rate. A thorough comparison between the superposition-rate and superposition-time methods is presented. The superposition-rate shows significant advantages over the superposition-time. A key improvement of the superposition-rate in quality diagnostics and data analysis is that it does not modify time scale. Consequently the superposition-rate keeps all production data in the sequence of their occurrence.
Open Access
A new model for flow regime recognition based on pore level simulation studies of tight gas formations
(2011) Rahmanian Shahri, Mohammad Reza; Aguilera, Roberto; Kantzas, Apostolos
Open Access
A New Production Casing Design to Withstand Combined Installation Compression Loading and High Multi-Stage Hydraulic Fracturing Pressures in Montney Shale Horizontal Wells
(2015-03-30) Suarez Jerez, Nino Alexander; Aguilera, Roberto
In order to make a low permeability shale reservoir economically attractive, it is critical to maximize the well contact with the reservoir by drilling long horizontal wells into the producing formation, and then to stimulate the well by means of massive multi-stage hydraulic fracturing. To this end, the well is equipped with a casing tubular system that initially serves as the pipe by which hydraulic fracturing is done, and subsequently acts as the conduit that transports hydrocarbons from the reservoir to the surface. In recent years, there has been production casing failures characterized by pipe leaking during hydraulic fracturing jobs in the Montney shale of British Columbia. Costs of these failures have ranged between $2MM and $15MM in NPV loss. These technical and economic failures have inspired the research presented in this thesis. Key contribution of this work: Development of a new tapered string made out of 22.4 x 17.3 kg/m casing, which takes into account all acting loads during casing installation and withstands high pressures during multi-stage hydraulic fracturing jobs in horizontal wells. The cost of the improved tapered string is similar to the cost of previous casing designs. Casing design has been traditionally done to withstand the most critical loads during the production phase of the well life. Fracturing loading has been incorporated into the casing design process merely as a casing burst load defined by the hydrostatic pressure of the fracturing fluid plus the surface pressure applied to that column of fluid. However, there has been minimum work done to incorporate the combined casing installation and hydraulic fracturing loads into the design process. The research presented in this thesis meets that need.
Open Access
An Experimental and Modelling Study to Evaluate the Potential of Low-salinity Waterflooding in a Tight Carbonate Reservoir
(2023-08-31) Singh, Navpreet; Sarma, Hemanta; Hassanzadeh, Hassan; Trivedi, Japan; Maini, Brij; Aguilera, Roberto
Over the years, the low-salinity water flooding (LSWF) process has received a lot of attention as a promising enhanced oil recovery (EOR) method due to its superior performance over conventional water flooding. It has been an area of great interest for the researchers for almost last three decades for its cost effectiveness and the potential benefit over other enhanced oil recovery (EOR) techniques. Conventional waterflooding is not as effective especially in carbonate reservoirs as they tend to be more oil wet. The objective of this study is to modify the ionic composition of the injection brine in a way that leads to higher incremental oil recovery for a specific carbonate reservoir. Before doing any of the experimental studies to study the rock-brine-oil interactions in a LSWF process, we characterized the physical and chemical properties of rock and fluid to understand the reservoir. Experimental components of this study included reservoir-condition high-pressure high-temperature (HPHT) displacement tests in composite cores using brines of different salinities and specially designed ionic compositions, investigation of wettability alteration in a unique and specifically designed HPHT imbibition cell, interfacial tension (IFT) studies and Zeta potential studies using a Zeta potentiometer that provided a more representative evaluation in brine-saturated whole cores rather than with pulverized samples. These studies gave us an insight to the rock-brine-oil interactions. Simulation studies involved flow simulation using geochemical reactions during LSWF, incorporating oil/brine/rock interactions, and linking laboratory data to simulation data from the given candidate reservoir. Findings of the coreflooding experiments conclusively showed that LSWF with certain specific ionic compositions yielded a higher oil recovery. HPHT imbibition tests provided visual and quantitative estimations and monitoring of how wettability alteration took place during LSWF and how it was impacted by the degree and magnitude of temperature and pressure. Zeta potentiometric studies enabled an investigation of the charging behavior at the rock-water interface at various salinities using a whole reservoir core rather than pulverized samples. A new method to estimate Zeta potential in a high-salinity environment was developed and validated, and it conclusively proved that rock-surface charge played a vital role in the LSWF process. Results of various experiments conducted indicated that lower ionic strength brine can yield higher oil recovery. Coreflooding experiments revealed that low ionic strength brine, particularly 1% diluted seawater (1% dSW) flooding, had the highest incremental recovery factor due to increased repulsive forces between the oil-brine and rock-brine surface. Zeta potential measurements showed that the addition of divalent anions, such as SO42-, to smart brine could generate more negative values than 1%dSW, but this must be weighed against the potential for sulfate ions to cause scaling on the porous formation and reduce fluid permeability. Divalent cations like Ca/Mg ions did not help in increasing oil recovery. Wettability alteration was observed as the dominant mechanism for improving oil recovery in LSWF experiments. IFT, Hele-shaw model and Zeta potential measurements indicated that rock-water interactions were more dominant than oil-water interactions. A statistical model was developed to predict the zeta potential for a given brine based on the comprehensive analysis of the various experiments. At the end, the simulation studies involved history matching of coreflooding displacement tests to predict the performance of various diluted brines, and incorporate various geochemical reactions occurring during a LSWF process. Developing a proper geochemical reservoir model requires the measurement of effluent concentration and history matching of effluent concentration. We used the geochemical reactions published in the literature to simulate LSWF process.
Open Access
An innovative approach for pore pressure prediction and drilling optimization in the abnormally sub-pressured "deep basin" of the western Canada sedimentary basin
(2011) Contreras Puerto, Oscar Michel; Aguilera, Roberto; Hareland, Geir
Up to now, an indirect method to predict pore pressure under sub-pressured conditions has not been reported in the literature. In this thesis, an im1ovative approach is presented for estimation of pore pressure and drilling optimization of wells drilled in the abnormally sub-pressured Deep Basin of the Western Canada Sedimentary Basin (WCSB). The procedure starts with detailed evaluation of five wells drilled in township T65-R09W6 that covers the study area. Pore pressure was calculated using Eaton method from sonic logs (Eaton, 1975), and Eaton method from the modified D exponent (Rehm and McClendon, 1971 ), which proved to be the most effective for abnormal sub-pressured conditions over a variety of methods tested. The drilling optimization procedure was carried out using the Apparent Rock Strength Log (ARSL); next, optimization of individual sections in each well was carried out to determine the optimum operational parameters for the lowest net drilling time. Special attention was focused on the tight gas N ikanassin Group for selection of the most suitable drilling parameters that increase the quality of drill cuttings. The combination of a rollercone bit code IADC 547 and at least 0.73 horsepower in the bit per square inch (HSI) provides the best quality of cuttings from the tight gas Nikanassin Group. This is of paramount importance for increasing accuracy in the quantitative determination of permeability and porosity from cuttings particularly in those tight gas reservoirs where the amount of cores is very limited. It is concluded that wells in the sub-pressured study area of the Deep Basin of the WCSB can be drilled efficiently with 7 bit runs reaching larger rates of penetration than achieved in practice so far, while at the same time reducing bit wear, controlling wellbore stability problems and recovering good quality drill cuttings. Although the methodologies developed in this thesis concentrate on township T65-R09W6 we anticipate that they can be extended to other sub-pressured formations with similar geologic characteristics in the Deep Basin of the WCSB and elsewhere.
Open Access
An integrated workflow for reservoir modeling and flow simulation of the Nikanassin tight gs reservoir in the western Canada sedimentary basin
(2011) Deng, Hui; Aguilera, Roberto; Settari, Anthony
This thesis presents an innovative workflow and learning curve for characterization and reservoir simulation of the tight gas Nikanassin Group in a study area, which centers primarily in Township 65 Range 09. The workflow and learning curve starts with LiDAR scanning of the Milk River Formation (porosities and permeabilities larger than 20% and 100 mD, respectively) in Writing on Stone Provincial Park (WOSPP), moves to rocks of the Doig Formation in British Columbia with poorer properties (about 6 to 9% porosity for clean sandstones and permeabilities of 0.7 to 34 mD) and closes the cycle evaluating rocks of the Nikanassin Group with even worse rock properties. The learning curve provides the necessary tools for studying the very complex, very heterogeneous Nikanassin Group characterized by porosities that are generally less than 5% and permeabilities that are typically a fraction of mD, i.e., properties much lower than the ones mentioned above for the Milk River and Doig formations. Previous petrographic studies of the Nikanassin Group show the presence of (1) intergranular, (2) microfracture + slot, and (3) isolated (non effective) porosities. These studies inspire the introduction of a mathematical triple porosity model for improved petrophysical analysis of the Nikanassin Group. Another novel approach developed in this thesis is the integration of lithofacies and pore throat apertures (rP35) that facilitate facies mapping for reservoir simulation purposes. Support to the reservoir simulation is given by geostatistical analysis and numerical well test evaluation. The result is a sound full field model that permits a reasonable match of production and pressure (limited amounts) histories, and forecasting of gas recovery under different well-spacing and depletion scenarios. As most Nikanassin tight gas wells are completed commingled, this research develops a procedure for production allocation of individual contributing formations. The study shows that there is a very large gas potential in the Nikanassin group, particularly in the Lower Monteith Formation that can be exploited by reducing significantly the well spacing. For example, detailed simulation indicates that doubling the number of Monteith wells in the study area will also double the cumulative gas production over a 10-year period. The finding is significant as the tight gas Nikanassin Group extends for more than 15,000 km² within Alberta and British Columbia. This suggests preliminary that there is potential for drilling thousands of Nikanassin well in these two provinces.
Embargo
Application of Nanoparticles in Regular and Foamed Cement-Based Systems
(2024-01-19) Mehairi, Ahmed; Husein, Maen; Khoshnazar, Rahil; Aguilera, Roberto; Chen, Shengnan (Nancy); Hassanzadeh, Hassan; Torabi, Farshid
Nano-modification of cement-based materials (CBMs) has the potential to enhance the mechanical properties of conventional CBMs and provide sustainable and energy-efficient solutions to mitigate the environmental footprint of cement manufacturing. Over the past years, the addition of nanoparticles (NPs) into cement paste, mortar, and concrete has shown outstanding enhancements in their mechanical properties and durability. Large-scale application of NPs in CBMs still, however, faces challenges such as improper dispersion, poor economics due to the cost of NPs, and potential health concerns associated with NPs handling. This work attempts to tackle these barriers by proposing inexpensive methods of NPs incorporation into oil well cement slurry and foamed concrete (FC). For oil well cement slurry, an easily scalable approach of NPs synthesis during cement slurry mixing is developed. Three methods for preparing in situ Fe(OH)3 NPs are presented. At 0.7 wt% of dry oil well cement, in situ prepared Fe(OH)3 NPs increases the 1-day compressive strength of the cement slurry by up to 90% and 38% at 25 oC and 80 oC, respectively, outperforming commercial NPs. Significant reductions in porosity (up to 48%) and permeability (up to 93%) are also achieved. Moreover, cement slurries with Fe(OH)3 NPs exhibit high resistance to fatigue from repeated compression cycles. In addition to oil well cement slurry, incorporation of NPs into FC through NP-stabilized preformed foams has been shown to overcome major FC drawbacks such as slurry instability and poor durability. In this study, the formulation of a stable in-house CaCO3 NPs/ hexadecyltrimethylammonium bromide (CTAB) dispersion is achieved. In the presence of pure N2 and a 2:1 CO2/N2 gas mixture, foams produced from this dispersion have half-lives of 5 – 6 h compared to 5 – 7 mins for CTAB alone. The presence of CaCO3 NPs also reduces the average bubble size by 67% and enhances foam thermal stability. The utilization of CaCO3 NPs/CTAB aqueous foam in FC improves slurry stability and leads to a narrower and more uniform pore size distribution than FC made with CTAB alone. CaCO3 NPs also accelerate the formation of hydration products and promote the formation of a denser solid matrix. These combined effects contribute to a less connected pore structure, reduction in atmospheric carbonation, and improved heat transfer and fire resistance properties.
Open Access
Characterization and Construction of 3D Numerical Simulators for Oil and Liquids-Rich Multi-Porosity Shale Reservoirs
(2017) Lopez Jimenez, Bruno Armando; Aguilera, Roberto; Mehta, Sudarshan A.; Moore, Robert Gordon; Harding, Thomas Grant; Bentley, Laurence Robert; Camacho-Velazquez, Rodolfo
Production from oil and shale gas-condensate reservoirs in the United States and Canada has increased during the past few years. However, an understanding of shale rocks and fluid flow through them is still limited. Thus, the objective of this research is to develop methodologies for characterizing multi-porosities in shale petroleum reservoirs and for simulating fluid flow of oil and condensates through these types of rocks. The characterization part is carried out with the use of (1) an original petrophysical model built for quantification of total organic carbon (TOC), Knudsen number, water saturation, and multiple porosities in shales, (2) measurement of gas permeability from shale samples in the laboratory using commercial equipment, and (3) an original laboratory-based correlation for estimating stress-dependent permeability, porosity and compressibility of tight rocks. The simulation part is carried out with the use of (1) an original radial numerical model developed for calculating sorption-dependent permeability of shales, (2) a commercial 3D model for investigating pore size-dependency of pressure-temperature envelopes in shale gas-condensate reservoirs, and (3) an original fully-implicit 3D-3phase pseudo-compositional model for oil and condensate shale reservoirs developed with capabilities to handle multiple porosities and stress-dependent properties of natural and hydraulic fractures. Key challenges include the handling of (1) adsorbed porosity, (2) organic porosity, (3) inorganic porosity, (4) natural fracture porosity, (5) hydraulic fracture porosity, (6) diffusion from solid kerogen, and (7) fluid transport in the small pores of shales, which deviate significantly from the behavior in conventional reservoirs. It is concluded that the methods developed in this thesis provide important foundation for the characterization and simulation of shale petroleum reservoirs.
Open Access
Characterization and Derivative-Free Algorithms for Faster Field Development Optimization of Liquids-Rich Shale Reservoirs.
(2019-05-08) Olusola, Bukola Korede; Aguilera, Roberto; Harding, Thomas Grant; Mehta, Sudarshan A. Raj; Moore, Robert Gordon Gord; Lines, Larry R.; Dehghanpour, Hassan
Petroleum exploration and development comes with high risks and capital spending. It is an essential goal to balance capital and operational requirements for selecting an optimal field development plan. Understanding the origin of oil, condensate and gas, and the rocks where these fluids are stored helps to achieve that essential goal. This research addresses those issues as current optimization methods applied to field development problems are computationally expensive. Thus, the objectives of this research are to develop methodologies for (1) understanding petroleum generation through millions of years and its link with current reservoir rocks, and (2) devising algorithms and procedures for optimizing fast and at low cost the production efficiency of shale oil reservoirs. The first objective is met with the use of a modified Pickett plot that is extended from a snapshot in time (the time in which well logs are run) to millions of years of burial and maturation trajectory. The approach is explained with data of the Niobrara shale. The plot is further extended for the evaluation of Biot coefficient, which is important to solve drilling and completion problems. Porosity and permeability from drill cuttings are included in the analysis. The second objective is met with the development of an original algorithm, termed in this thesis climbing swarms (CS) algorithm, which is used for well control and design optimization problems. The CS is coupled first with a numerical simulator and next with a material balance. The CS converges faster to a higher quality solution and provides advantages over existing field development optimization methods. An application using Eagle Ford shale data is presented for optimizing oil recovery during Huff and Puff gas injection and re-fracturing operations. It is concluded that the methods developed in this thesis allow faster learning and at lower cost regarding possible field development plans for shale petroleum reservoirs, a task that would be time consuming, tedious and not as accurate, if carried out manually.
Open Access
Characterization of tight and shale unconventional gas reservoirs using low field NMR
(2023-01-26) Solatpour, Razieh; Kantzas, Apostolos; Torabi, Farshid; Aguilera, Roberto; Clarkson, Christopher; Chen, Shengnan; Wong, Ron
Unconventional petroleum resources, especially tight and shale reserves, constitute an increasing frontier of reserves additions as conventional production declines. In these sources, reservoir characteristics have significant value in reserve estimation and flow modelling. These characteristics are challenging parameters to measure. On the other hand, oil and gas sectors are continually looking for ways to do more with less environmental impact and greater operational efficiency. Nuclear Magnetic Resonance (NMR) offers fast and non-disruptive detection of the reservoir samples properties. The purpose of this research is to investigate the interactions between tight and shale rocks with hydrocarbons using NMR technique. This thesis mainly presents routine and new experimental and numerical methods of measuring porosity, permeability, residual saturations, and excess and absolute adsorption isotherms. The experiments were conducted on different porous media such as shale cores, tight sand cores, activated carbon, and sandpacks at pressures up to 7 MPa. In this thesis, for 150 cores, permeability was estimated using all existing NMR permeability correlations. In addition, irreducible saturations were presented for these cores. A new method to obtain residual saturation using the area under the NMR relaxation distribution curves was introduced. Permeability and irreducible saturation models are compared based of their standard error deviation from the independently measured ones. For organic porous media, the NMR decay curve of hydrocarbons exhibited a logarithmic behaviour at early times. Based on this observation, a new method of obtaining absolute adsorption was developed. The time when the decay curve shifts from logarithmic to multi-exponential behaviour was defined as sorption cut-off time. Adsorption isotherm hysteresis of methane in Duvernay shale samples was demonstrated using the newly developed method. In this research, for the first-time Low-Field NMR relaxometry with a frequency close to logging tools directly and without the use of correlations is used for quantitative determination of adsorption isotherms of methane in shale reservoirs. Isotherms derived by the new method better described the physical behaviour of hydrocarbon in organic porous media as it captures the effect of phase transition and measures critical pressure in organic porous media, which is different than the ones in non-organic porous media. Moreover, with this new fractal model, total hydrocarbon in place, adsorbed, and free hydrocarbon can be estimated from a single NMR experiment. This thesis is beneficial in understanding existing tight and shale reservoir characterization methods and introduces more advanced and reliable techniques to measure the properties of these reservoirs. In chapter 3 to 7 of this study, currently available methods of tight and shale reservoir characterization are presented. Then a new approach is provided for each case which is less computationally demanding, and calculations are easier to perform. Moreover, in most scenarios only a single NMR measurement is needed.
Open Access
A Comparison of Oil Recovery from Shale Reservoirs by Huff and Puff Gas Injection Using Methane, Rich Gas, Carbon Dioxide, Nitrogen and Flue Gases
(2022-01-13) Bao, Xiaolin; Aguilera, Roberto; Moore, Robert Gordon; Mehta, Sudarshan A. (Raj)
This thesis investigates the effect of Huff and Puff (H&P) gas injection on oil recovery from shale reservoirs. H&P is performed in multi-stage hydraulically fractured horizontal wells with data sets representative of the Eagle Ford shale in Texas. Different injection gases are used including methane (CH4), carbon dioxide (CO2), rich gas (70% CH4, 20% propane C3H8, plus 10% hexane C6H14), nitrogen (N2) and flue gases with different combinations of N2 and CO2; 25 cases are investigated using a compositional reservoir simulator. The thesis also discusses some ideas regarding geologic containment of fluids in inverse order in the same structure (gas at the bottom, condensate in the middle and oil at the top), and the importance of containment for conducting successful H&P gas injection projects. The geologic containment idea is also useful for advancing the possibility of Carbon Capture, Utilization and Storage (CCUS) of the CO2 employed for H&P gas injection.
Open Access
Completion and Stimulation Optimization of Montney Wells in the Karr Field
(2015-02-11) Popp, Melanie; Aguilera, Roberto
The Montney formation in the Karr field has been identified as a very prolific target in today’s price environment due to its liquids rich potential. The profitability of the play depends greatly on reducing the amount of capital spent to exploit the resource. The operator has drilled and stimulated 4 horizontal wells in the area with a variety of placement issues, resulting in additional costs. An examination of the data from the problem wells identifies two major sources of premature screen outs and recommendations are made to mitigate this in the short term. A paradigm shift led to the creation of a fracture model such that the optimal fracture treatment design can be obtained. Finally, recommendations to whole well completion tactics are made resulting in a more prosperous well.
Open Access
Concentration Dependent Diffusion of Solvent in Heavy Oil
(2020-01-20) Carril Naranjo, José Eduardo; Kantzas, Apostolos K.; Aguilera, Roberto; Maini, B. B.
In recent years, solvent-based methods have arisen as a feasible alternative to thermal schemes for heavy oil recovery, owed to the diffusive solvent mass transfer effect on oil mobility. The increasing incorporation of significant diffusion physics to models describing the process will lead to successful field implementations. In this work, a numerical model that captures the solvent diffusion coefficient dependence, on its concentration in solvent – bitumen / heavy oil systems, was developed and tested. The interFoam solver was enabled to account for two phases and a miscible component diffusing between them. Then, one-dimensional diffusion simulations were conducted to validate its results against analytical solutions. Once the two phases and miscible component diffusion features were validated, the solvent diffusivity concentration dependence feature was added to the numerical model. This attribute was later evaluated against experimental measurements of solvent concentration evolution in heavy oil and bitumen. To this end, results from two experimental works were considered as reference. This study demonstrates that the diffusivities observed in the solvent – heavy oil / bitumen systems analysed can be numerically handled by the model presented. Additionally, the solvent concentration dependence feature makes of the model an important tool to evaluate its effect on viscous oil and it can potentially be implemented in pore scale models.
Open Access
Controlling Factors on Condensate Production from the Eagle Ford Shale
(2015-07-09) Wang, Yi; Aguilera, Roberto
This thesis examines the impact on recovery from shale condensate reservoirs of key properties such as porosity and permeability as well as other controlling factors that include the horizontal wells length, liquid drop out and liquid loading around the wellbore. It also addresses the possibility of lean gas injection. It is found that production of heavy ends (C5, C6 and C7) remains low with time but at an approximate constant rate. The dual permeability model shows larger production of C5, C6 and C7 as compared with the dual porosity model. A higher natural fracture permeability results in an increased production and recovery. The preliminary conclusion is reached that lean injection is not feasible when shale permeability is within the range considered in this study (0.0001 md). However, there might be sweet spots within condensate shale reservoirs amenable to enhanced oil recovery. It is recommended to investigate this possibility.
Open Access
Coupling Geochemical, Geomechanical and Petrophysical Data for Identifying Potential Moveable Hydrocarbon Zones in Shale Oil Reservoirs
(2016) Piedrahita Rodriguez, Jaime Alberto; Aguilera, Roberto; Gates, Ian; Meyer, Rodolfo
This research aims at integrating geochemical, petrophysical and geomechanical models of shale oil reservoirs built with data gathered from laboratory tests and well logs. The main objective is to identify intervals that contain free oil. The objective is achieved by developing new analytical models that permit interpreting the internal anatomy of the rock including its composition. The main challenge is that shale oil reservoirs are multi-porosity systems composed by natural fractures, inorganic matter and organic matter where the latter develops its own porosity. Results show a good agreement between free oil detected with the geochemical model and those zones with high total porosity and/or high natural fracture intensity. Although total organic carbon content in shale oil reservoirs is important, it is more meaningful to determine the volumes of free oil and how it is distributed in the shale pore space.
Open Access
Development of a Comprehensive and General Approach to In Situ Combustion Modelling
(2024-03-26) Gutiérrez, Dubert; Moore, Robert Gordon; Mehta, Sudarshan A.; Aguilera, Roberto; Hejazi, Hossein; Hassanzadeh, Hassan; Jia, Na
Modelling of the in situ combustion (ISC) process is a challenging task, mostly due to the complexity of the chemical reactions taking place. Also, the applicability of currently available kinetic models is typically limited to the reservoir systems they were originally developed for. The objective of this study was to derive a general chemical reaction framework that could be used to develop a kinetic model for a wide variety of crude oils. The work is based on the modelling of high-pressure ramped temperature oxidation (HPRTO) experiments, and combustion tube (CT) tests, performed on three different oil systems: a volatile oil which is near critical at reservoir conditions (38.8°API), a low-shrinkage light oil (33.1°API), and a bitumen sample (6.5°API). A kinetic model was derived for each of the cases based on the history match of a HPRTO experiment. The resulting models were validated by history matching a CT test for each of the crude oils, while using the same set of developed reactions. The modelling approach chosen is an extension of the methodology originally proposed by Belgrave et al. in 1993, which is arguably the most comprehensive kinetic model available in the air injection literature. However, their model was developed from experiments performed on Athabasca bitumen, and it fails to represent the ISC process as it occurs in light oil reservoirs encountered at high pressure. For example, Belgrave’s model is based on the deposition and combustion of semi-solid residue commonly known as “coke”, which is rarely present during the ISC of light oils at high pressure. As in Belgrave’s model, this study also describes the original oil in terms of maltenes and asphaltenes. The main difference lies on the presence and importance of oxygen-induced cracking reactions, as well as the combustion of a flammable mixture, which takes place in the gas phase. Also, a unique feature of these simulations is that, apart from history matching traditional variables such as thermocouple temperatures, produced gas composition and fluid recovery, they also capture changes in the physical properties of the produced oil, such as viscosity and density, as well as the amount of the residual phases in the post-test cores. This thesis changes a paradigm deeply rooted in the original ISC theory, by deriving a general chemical reaction framework that is used to develop a kinetic model for a wide variety of crude oils, with API gravities ranging between 6.5 and 38.8. This allows the consolidation of a new and comprehensive general theory for the description of the in situ combustion process as applied to oil reservoirs. One of the features of the modelling approach is that the pseudo-components representing the fuel used by the ISC process are not present in the original oil. Such fuel species are products of oxidation and cracking reactions, which may undergo combustion reactions when in contact with oxygen. Therefore, the method is not limited to a fluid characterization based in terms of maltenes and asphaltenes, and could potentially be applied along with any other type of characterization of the original oil. This facilitates its implementation and coupling with existing field-scale models (i.e., black oil, thermal, or fully compositional), which seek to assess the feasibility of the in situ combustion process on a particular reservoir of interest.
Open Access
Development of a ‘Quad Porosity’ Numerical Flow Model for Shale Gas Reservoirs
(2013-01-25) Swami, Vivek; Settari, Antonin; Aguilera, Roberto
Shale gas production modeled with conventional simulators/models is often lower than actually observed field data, even when the effect of hydraulic fractures is taken into account. This is currently being explained by the development of secondary fracturing (the stimulated reservoir volume). While such geomechanical effects are often dominant, it is likely that other factors also contribute to the observed productivity, and these need to be quantified in order to understand the relative importance of all mechanisms. This work addresses one of these factors, namely the complexity of fluid flow physics in nanopore-size porous media. Traditionally, it has been perceived that in shale gas reservoirs gas is stored only in pore space (matrix pores and natural fractures) and adsorbed on pore surfaces. But with recent development in the visualization and measurement techniques, additional gas has been found dissolved in organic matter. In this work, a numerical model for complex ‘quad porosity’ system in shale reservoirs is proposed while also accounting for non-Darcy flow in shale nanopores. We begin with a theoretical model for gas flow inside one shale nanopore and upscale it to laboratory sample scale. Consequently, this model can be incorporated in a commercial reservoir simulator to simulate the flow behavior of shale gas reservoirs with higher confidence. This will help to improve reservoir modeling for shales and correctly predicting the gas in place and recovery.
Open Access
Drill Cuttings, Petrophysical, and Geomechanical Models for Evaluation of Conventional and Unconventional Petroleum Reservoirs
(2013-09-23) Olusola, Bukola; Aguilera, Roberto
This thesis concentrates on some of the aspects of a ‘Total Petroleum System’ including natural gas and oil stored in conventional and unconventional reservoirs. The original contributions of this thesis include: 1) The use of electromagnetic mixing rules for construction of dual and triple porosity models with a view to quantifying matrix, fracture and non-effective porosity and the porosity exponent (m) of naturally fractured reservoirs. 2) The use of electromagnetic mixing rules for construction of dual and triple porosity models with a view to quantify the water saturation exponent (n) and to estimate the wettability of reservoir rocks in naturally fractured reservoirs. 3) Measurements of porosity and permeability in drill cuttings collected directly in a horizontal well. Although these measurements have been carried out previously in drill cuttings collected in vertical and deviated wells, this is the first time that they are performed in horizontal well drill cuttings. The models developed in Items 1 and 2 are compared successfully against core laboratory data. Water and/or oil stored in each of the porous media considered in the models, affects rock wettability and consequently the values of n. Robustness of the models is important because, in practice, while logging a well in a naturally fractured reservoir, the tool will probably go through some intervals with only matrix porosity; some intervals with matrix porosity and fractures, some with matrix porosity and isolated porosity; and some intervals with matrix, fractures and non-connected porosities. As there are variations in the contribution of each porosity system with depth, there are also variations in m with depth that have to be taken into account. The laboratory measurements of porosity and permeability from drill cuttings mentioned above in Item 3 were conducted at the University of Calgary. Based on a thorough review of literature this is the first time that this measurements are conducted in drill cuttings samples collected in horizontal wells. Starting with only drill cuttings measurements of porosity and permeability, the methodology developed in this thesis allows for complete formation evaluation and geomechanical analysis through the use of a successive approach for determination of several parameters of interest including pore throat aperture radius (rp35), water saturation, porosity exponent (m), true formation resistivity, capillary pressure, Knudsen number, depth to the water contact (if present), construction of Pickett plots, Young’s Modulus, Poisson’s ratio and brittleness index throughout the horizontal length of the well, and for locating the best hydraulic fracture initiation points during multi-stage fracturing jobs. It is concluded that the use of electromagnetic mixing rules and drill cuttings provide a valuable and practical addition for quantitative characterization of conventional and unconventional petroleum reservoirs.