Дисертації з теми "Enhance gas recovery"

Perhaps no other single theme offers such potential for the petroleum industry and yet is never fully embraced as enhanced hydrocarbon recovery. Thomas et al. (2009, p. 1) concluded their review article with “it appears that gas condensate reservoirs are becoming more important throughout the world. Many international petroleum societies are beginning to have conferences specifically oriented to gas condensate reservoirs and discussing all parameters germane to such systems.” Gas condensate reservoirs however, usually experience retrograde thermodynamic conditions when the pressure falls below the dewpoint pressure. Condensate liquid saturation builds up near the wellbore first and then propagates radially away along with the pressure drop. This liquid saturation throttles the flow of gas and thus reduces the productivity of a well by a factor of two to four (Afidick et al., 1994; Barnum et al., 1995; Smits et al., 2001; Ayyalasomayajulla et al., 2005). The severity of this decline is to a large extent related to fluid phase behaviour, flow regime (Darcy or non-Darcy), interfacial forces between fluids, capillary number, basic rock and fluid properties, wettability, gravitational forces as well as well type (well inclination, fractured or non-fractured).Thomas et al. (2009, p. 4) added “... for gas condensate systems which exhibit high interfacial tensions where the pore throats are very small, which may correspond either to low permeability rocks or high permeability rocks but with very large coordination number, the success of flowing the liquid from the rock, once it has condensed, will be limited. In such cases, vaporisation (lean gas cycling) or injection of interfacial tension reducing agents (CO2) may be the only option to enhance the performance.” In their comparison of several EOR mechanisms, Ollivier and Magot (2005, p. 217) reported “since large changes in viscous forces are only possible for the recovery of heavy oil, the reduction (or entire elimination) of interfacial forces by solvents such as injection gases seems to be a practical way to achieve large changes in capillary number.” While the majority of the state of the art publications cover sensational aspects of gas condensate reservoirs such as phase couplings and mass transfer between original reservoir components, very little has been reported on fluid dynamics and interfacial interactions of CO2 injection into such systems. This, along with the conceptual frameworks discussed above, serves as the motive for this research work.High pressure high temperature experimental laboratories that simulate reservoir static and thermodynamic conditions have been established to evaluate the: (1) effectiveness of CO2 injection into gas condensate reservoirs through interfacial tension (IFT) and spreading coefficients measurements at various reservoir conditions, (2) efficiency of the process through recovery performance and mobility ratio measurements; with special emphasis on the rate-dependent, IFT-dependent, and injection gas composition-dependant relative permeabilities, and (3) the behaviour of CO2 injection into gas condensate reservoirs on a field scale through numerical simulations in heterogeneous, anisotropic, fractured and faulted systems. The study also investigates the performance of various reservoir fluid thermodynamic conditions, injection design variables, and economic recovery factors associated with CO2 injection.Condensate recovery was found to be a strong function of CO2 injection pressure (and thus IFT), displacement flow rate, injection gas composition as well as phase behaviour and fluid properties. These parameters control the orientation and continuity of the fluid phases, solubility, gravity segregation, mobility ratio, and the ultimate recovery efficiency. Simulation analysis also suggests that developments of fractured gas condensate reservoirs depend to a large extent on initial reservoir thermodynamic conditions (initial pore pressure and fluid composition) as well as on production operations (natural depletion, waterflooding, continuous CO2 injection, gas injection after waterflooding GAW, or water alternating gas WAG).Much like the interrelation between accuracy and precision in science and engineering statistics, this research work draws a link between the effectiveness (quality metric through IFT measurements) and the efficiency (productivity metric through coreflooding experiments) of CO2 injection into gas condensate reservoirs. The data reported in this research work should help reservoir engineers better characterise gas condensate systems. The results can also aid the engineering design of CO2-EOR and CO2 sequestration projects.

The central issue in the physical processes of enhanced gas recovery by carbon dioxide (CO[subscript]2) injection is the extent to which the natural gas will mix with the injected CO[subscript]2 and reduce the calorific value of the natural gas. Mixing in such a system is a diffusion-like process, which definitely depends on the physical properties of the displacing and displaced phases and the heterogeneity of the medium. However CO[subscript]2 undergoes a large change in density in the gas phase as it passes through the critical pressure at temperatures near the critical temperature. At the extreme reservoir conditions with pressure of 6000 psi and temperature of 160 ºC, CO[subscript]2 exhibits a greater viscosity and density when compared to methane. This variation is approximately a factor of three, which is in favour of the CO[subscript]2-natural gas displacement. In contrast, at near supercritical conditions of pressure of 1071 psi and temperature of 31 ºC, the CO[subscript]2 physical properties (viscosity and density) are slightly superior methane’s. Results indicated improved recovery efficiency was obtained with tests that were conducted at higher pore pressure, higher displacement speed and higher methane concentration in the in situ gas. In addition, low quality rock at a lower temperature of 95 ºC also showed better ultimate recovery.In this work, the first ever attempt for measuring interfacial tension (IFT) in a Gas- Gas system, namely supercritical carbon dioxide (SCO[subscript]2) and methane was made. Experiments were conducted at temperatures of 95 °C and 160 °C and pressures from 1000 to 6000 psia, using a modified reverse pendant drop method. It is common knowledge that a thermodynamically stable interface can only exist between two immiscible fluids, nonetheless an “immiscible interface” between two gases (CO[subscript]2- methane) has been observed and is documented within this research work.It was noted that the IFT decreased linearly with both temperature and pressure in the low-pressure range, but was less sensitive at higher pressures. There was a zone in the vicinity of 1500 psia and above that was noted to be independent of temperature where IFT increased sharply. The IFT was almost three times higher at 3000 psia, for the same temperature, compared with 1000 psia. This is attributed to the density of SCO[subscript]2 at 1000 psia being less than 1/3 the density at 3000 psia, at the same temperature.

Thesis (Ph.D.)--Southern Illinois University Carbondale, 2005.
"Department of Mining and Mineral Resources Engineering." Includes bibliographical references (leaves 126-138). Also available online.

Carbon Capture and Storage (CCS) is considered as an important solution for CO₂ emission reduction, yet, the CO₂ capture process is highly costly. Thus, combining Enhanced Gas Recovery (EGR) with CCS could potentially offset the costs via additional production of natural gas. Therefore, the objective of this P.hD. is to build a numerical model to simulate CO₂-EGR in partially-depleted gas reservoirs; in particular Centrica Plc's North Morecame gas field. Our numerical model is based on the so-called Method of Lines (MOL) approach. MOL requires selecting a set of persistent Primary Dependent Variables (PDVs) to solve for. In this case, we chose to solve for pressure, temperature and component mass fractions. Additionally, MOL requires recasting of the governing equations in terms of the PDVs, which often requires the evaluation of partial derivative terms of the flow properties with respect to the PDVs. In this work, a method of analytical evaluation of these partial derivative terms is introduced. Furthermore, in a new approach, the mutual solubility correlations for mixtures of CO₂-H₂O and CH₄-H₂O, available in the literature, are joined together using straight lines as a ternary diagram, to form a ternary CO₂-CH₄-H₂O equilibrium model; the equilibrium-model's predictions matched well with the available experimental solubility data. 1D and 2D numerical simulations of CO₂-EGR were carried out. Overall, the 1D results were found to match very well with an existing analytical solution, predicting accumulation of a CH₄ bank ahead of the CO₂ plume and accurately locating the associated shock fronts while considering the partial miscibility of both CO₂ and CH₄ in H₂O. Based on the subsequent model predictions, in the North Morecambe field without drilling any additional wells, 0.6 out 2.3 BSCM, i.e., 26% of the remaining gas can potentially be recovered using CO₂-EGR.

Geologic sequestration of CO2 into unmineable coal seams is proposed as a way to mitigate the greenhouse gas effect and potentially contribute to economic prosperity through enhanced methane recovery. In 2009, the Virginia Center for Coal and Energy Research (VCCER) injected 907 tonnes of CO2 into one vertical coalbed methane well for one month in Russell County, Virginia (VA). The main objective of the test was to assess storage potential of coal seams and to investigate the potential of enhanced gas recovery. In 2014, a larger scale test is planned where 20,000 tonnes of CO2 will be injected into three vertical coalbed methane wells over a period of a year in Buchanan County, VA. During primary coalbed methane production and enhanced production through CO2 injection, a series of complex physical and mechanical phenomena occur. The ability to represent the behavior of a coalbed reservoir as accurately as possible via computer simulations yields insight into the processes taking place and is an indispensable tool for the decision process of future operations. More specifically, the economic viability of projects can be assessed by predicting production: well performance can be maximized, drilling patterns can be optimized and, most importantly, associated risks with operations can be accounted for and possibly avoided. However, developing representative computer models and successfully simulating reservoir production and injection regimes is challenging. A large number of input parameters are required, many of which are uncertain even if they are determined experimentally or via in-situ measurements. Such parameters include, but are not limited to, seam geometry, formation properties, production constraints, etc. Modeling of production and injection in multi-seam formations for hydraulically fractured wells is a recent development in coalbed methane/enhanced coalbed methane (CBM/ECBM) reservoir modeling, where models become even more complex and demanding. In such cases model simulation times become important. The development of accurate simulation models that correctly account for the behavior of coalbeds in primary and enhanced production is a process that requires attention to detail, data validation, and model verification. A number of simplifying assumptions are necessary to run these models, where the user should be able to balance accuracy with computational time. In this thesis, pre- and post-injection simulations for the site in Russell County, VA, and preliminary reservoir simulations for the Buchanan County, VA, site are performed. The concepts of multi-well, multi-seam, explicitly modeled hydraulic fractures and skin factors are incorporated with field results to provide accurate modeling predictions.
Ph. D.

Permanently sequestering carbon dioxide (CO2) in gas-bearing shale formations is beneficial in that it can mitigate greenhouse gas emissions as well as enhance gas recovery in production wells. This is possible due to the sorption properties of the organic material within shales and their greater affinity for CO2 over methane. The phenomenon of preferentially adsorbing CO2 while desorbing methane has been proven in coalbed reservoirs successfully, and is feasible for shale formations. The objective of this thesis is to explore the potential for enhanced gas recovery from gas-bearing shale formations by injecting CO2 into a targeted shale formation. With the advancement of technologies in horizontal drilling combined with hydraulic fracturing, shale gas has become a significant source of energy throughout the United States. With over 6,000 trillion cubic feet (Tcf) of theoretical gas-in-place, Appalachia has proven a major basin for gas production from organic shales. With its extensive shale reserves and lack of conventional reservoirs typically used for CO2 storage, Appalachia's unconventional reservoirs are favorable candidates for CO2 storage with enhanced gas recovery. Enhancing gas recovery not only increases reserves, but extends the life of mature wells and fields throughout the basin. As part of this research, 510 tons of CO2 were successfully injected into a horizontal production well completed in the Chattanooga shale formation, a late Devonian shale, in Morgan County, Tennessee. An extensive monitoring program was implemented during the pre-injection baseline, injection, soaking, and flowback phases of the test. Multiple fluorinated tracers were used to monitor for potential CO2 breakthrough at offset production wells and to help account for the CO2 once the well was flowed back. Results from this test, once the well was put back into normal production state, confirm the injectivity and storage potential of CO2 in shale formations, as well as an increase in gas production rate and quality of gas produced.
Master of Science

Two main topics are treated in this doctoral thesis from a theoretical and computational point of view: the gas capture and separation from post-combustion flue gases, and the enhanced oil recovery from oil reservoirs. The first topic evaluates the separation of CO2 using three different materials. First, several zeolites from the Faujasite family are studied with a combination of Density Functional Theory (DFT) and Monte Carlo methods. The former is employed to understand the driving mechanisms of adsorption, whereas the latter served to assess the separation of CO2 from a flue gas formed by a ternary mixture of CO2, N2 and O2. Second, the adsorption of CO2, N2 and SO2 into Mg-MOF-74 obtained through DFT calculations is presented to determine the most fundamental gas/MOF interactions. The results are then coupled to a Langmuir isotherm model to derive the macroscopic adsorption isotherms of the three gases in Mg-MOF-74. Finally, the absorption of CO2 and SO2 into three different phosphonium-based Ionic Liquids (ILs) is addressed by using the soft-SAFT equation of state and the COSMO-RS model. From the calculated adsorption/absorption isotherms several properties are obtained, such as the purity in the recovered gas, the working capacity of the materials and their selectivity to capture CO2 in the presence of other contaminant species. The main results obtained from this part of the thesis reveal that the cations of microporous materials are very strong sites of absorption for polar gases (i.e., the Na+ cations in Faujasites or the Mg2+ cations in Mg-MOF-74). This feature makes them very good candidates for CO2 capture, but they can be easily poisoned by other polar gases such as SO2. For this reason, it is highly recommended to desulphurize the flue gas before using any of these adsorbents. Similarly, ILs have higher affinity for SO2 than for CO2. However, the gas/IL interactions are significantly weaker, so they do not become poisoned by SO2. This fact implies that SO2 can be captured and separated from the flue gas by using a phosphonium-based IL. The second topic describes via Molecular Dynamics simulations the interactions of several model oils with different rocks and brines. The obtained insight can be applied in better understanding the interactions of the species present at oil reservoirs, with direct application in enhanced oil recovery processes. To that end, two wettability indicators are monitored to determine the potential recovery of the model oils. First, the oil/water interfacial tension (IFT) under different conditions of temperature, pressure and salinity (i.e., from pure water to 2.0 mol/kg of NaCl or CaCl2). And second, the oil/water/rock contact angle (CA) on calcite (10-14) and kaolinite (001) also as a function of salinity (i.e., from pure water to 2.0 mol/kg of NaCl or CaCl2). The different model oils are built with molecules of different chemical nature representing the Saturate/Aromatic/Resin/Asphaltene (SARA) fractionation model. In a final stage of the doctoral thesis the effect of non-ionic surfactants at the oil/brine IFT is also included. The main results obtained show that the most polar components of oil migrate to the oil/water interface and reduce the IFT. However, the same compounds feel attracted to the rock, who increase the CA and hamper the oil recovery. Some of these interactions are affected by the presence of salt. Specifically, if a water layer is formed between the oil and the rock in a reservoir, electrolytes can diffuse into it and attract the polar components of oil, ultimately increasing the CA. Finally, cations can be attracted to the oil/water interface due to salt/surfactant interactions. Both species interact synergistically to modify their orientation/distribution at the interface and reduce the oil/water IFT.
En aquesta tesi doctoral s’han tractat dos temes principals des d’una perspectiva teòrica i computacional: la captura i separació de gasos de post-combustió, i la recuperació millorada de petroli. El primer tema avalua la separació de CO2 utilitzant tres materials diferents. Primer, s’han estudiat diverses zeolites de la família de les Faujasites amb una combinació de teoria del funcional de la densitat (TFD) i mètodes Monte Carlo per entendre els mecanismes d’adsorció separació de CO2 d’una mescla ternària que conté CO2, N2 i O2. Seguidament, s’ha presentat un estudi TFD d’adsorció de CO2, N2 i SO2 en Mg-MOF-74 per determinar les interaccions fonamentals del MOF amb cada gas. Aquesta informació s’ha acoblat a un model d’isoterma de Langmuir per tal de derivar les isotermes d’adsorció macroscòpiques dels tres gasos en Mg-MOF-74. Finalment, s’ha analitzat l’absorció de CO2 i SO2 en tres Líquids Iònics (LIs) basats en fosfoni mitjançant l’equació d’estat soft-SAFT i el model COSMO-RS. D’altra banda, el segon tema descriu les interaccions de diferents models de petroli amb roques i salmorres, via simulacions de Dinàmica Molecular. El coneixement adquirit en aquesta part de la tesi doctoral es pot aplicar directament a la recuperació millorada de petroli i per entendre millor les interaccions de les espècies presents als pous. Amb aquesta finalitat, s’han controlat dos indicadors de la mullabilitat per determinar la recuperació potencial d’aquests models de petroli. Primer la tensió interfacial (TIF) oli/aigua sota diferents condicions de temperatura, pressió i salinitat (des d’aigua pura a 2.0 mol/kg de NaCl o CaCl2). I segon, l’angle de contacte oli/aigua/roca en calcita (10-14) i caolinita (001) en funció de la salinitat (des d’aigua pura a 2.0 mol/kg de NaCl o CaCl2). Els diferents models de petroli s’han construït amb molècules de diferent naturalesa química representant el model de fraccionament Saturat/Aromàtic/Resina/Asfaltè (SARA). En una etapa final de la tesi doctoral s’ha inclòs l’efecte en la TIF induïda pels surfactants no-iònics a la interfase oli/salmorra.

Thesis: S.M., Massachusetts Institute of Technology, Department of Mechanical Engineering, 2014.
Cataloged from PDF version of thesis.
Includes bibliographical references (pages 135-147).
Oxy-fuel combustion of sour gas, a mixture of natural gas (primarily methane (CH 4 )), carbon dioxide (CO 2 ), and hydrogen sulfide (H 2 S), could enable the utilization of large natural gas resources, especially when combined with enhanced oil recovery (EOR). Chemical kinetic modeling can help to assess the potential of this approach. In this thesis, a detailed chemical reaction mechanism for oxy-fuel combustion of sour gas has been developed and applied for studying the combustion behavior of sour gas and the design of power cycles with EOR. The reaction mechanism was constructed by combining mechanisms for the oxidation of CH4 and H2S and optimizing the sulfur sub-mechanism. The optimized mechanism was validated against experimental data for oxy-fuel combustion of CH4, oxidation of H2S, and interaction between carbon and sulfur species. Improved overall performance was achieved through the optimization and all important trends were captured in the modeling results. Calculations with the optimized mechanism suggest that increasing H2 S content in the fuel tends to improve flame stability through a lower ignition delay time. Water diluted oxy-fuel combustion leads to higher burning velocities at elevated pressures than CO 2 dilution or air combustion, which also facilitates flame stabilization. In a mixed CH4 and H2S flame, H25 is oxidized completely as CH4 is converted to carbon monoxide (CO). During CO burnout, some highly corrosive sulfur trioxide (SO3 ) is formed. Quenching of SO 3 formation in the combustor can only be achieved at the expense of higher CO emissions. The modeling of a gas turbine cycle showed that oxy-fuel combustion leads to SO 3 concentrations that are one to two orders of magnitude lower than in air combustion and will thus suffer much less from the associated corrosion problems. Slightly fuel-rich operation is most promising for achieving the low CO and oxygen (02) concentrations required for EOR while further minimizing SO 3. Carbon dioxide dilution is better for achiving low 02 in the EOR stream while H20 gives the better combustion efficiency.
by Dominik Bongartz.
S.M.

The rapid electrification through natural gas in Mexico; the interest of the country to mitigate the effects of climate change; and the opportunity for rolling out Enhanced Oil Recovery at national level requires an important R&D effort to develop nationally relevant CCS technology in natural gas combined cycle power plants. Post-combustion carbon dioxide capture at gas-fired power plants is identified and proposed as an effective way to reduce CO2 emissions generated by the electricity sector in Mexico. In particular, gas-fired power plants with carbon dioxide capture and the sequential combustion of supplementary natural gas in the heat recovery steam generator can favourably increase the production of carbon dioxide, compared to a conventional configuration. This could be attractive in places with favourable conditions for enhanced oil recovery and where affordable natural gas prices will continue to exist, such as Mexico and North America. Sequential combustion makes use of the excess oxygen in gas turbine exhaust gas to generate additional CO2, but, unlike in conventional supplementary firing, allows keeping gas temperatures in the heat recovery steam generator below 820°C, avoiding a step change in capital costs. It marginally decreases relative energy requirements for solvent regeneration and amine degradation. Power plant models integrated with capture and compression process models of Sequential Supplementary Firing Combined Cycle (SSFCC) gas-fired units show that the efficiency penalty is 8.2% points LHV compared to a conventional natural gas combined cycle power plant with capture. The marginal thermal efficiency of natural gas firing in the heat recovery steam generator can increase with supercritical steam generation to reduce the efficiency penalty to 5.7% points LHV. Although the efficiency is lower than the conventional configuration, the increment in the power output of the combined steam cycle leads a reduction of the number of gas turbines, at a similar power output to that of a conventional natural gas combined cycle. This has a positive impact on the number of absorbers and the capital costs of the post-combustion capture plant by reducing the total volume of flue gas by half on a normalised basis. The relative reduction of overall capital costs is, respectively, 9.1% and 15.3% for the supercritical and the subcritical combined cycle configurations with capture compared to a conventional configuration. The total revenue requirement, a metric combining levelised cost of electricity and revenue from EOR, shows that, at gas prices of 2$/MMBTU and for CO2 selling price from 0 to 50 $/tonneCO2, subcritical and supercritical sequential supplementary firing presents favourably at 47.3-26 $/MWh and 44.6-25 $/MWh, respectively, compared with a conventional NGCC at 49.5-31.7 $/MWh. When operated at part-load, these configurations show greater operational flexibility by utilising the additional degree of freedom associated with the combustion of natural gas in the HRSG to change power output according to electricity demand and to ensure continuity of CO2 supply when exposed to variation in electricity prices. The optimisation of steady state part-load performance shows that reducing output by adjusting supplementary fuel keeps the gas turbine operating at full load and maximum efficiency when the net power plant output is reduced from 100% to 50%. For both subcritical and supercritical combined cycles, the thermal efficiency at part-load is optimised, in terms of efficiency, with sliding pressure operation of the heat recovery steam generator. Fixed pressure operation is proposed as an alternative for supercritical combined cycles to minimise capital costs and provide fast response rates with acceptable performance levels.

A storage and enhanced coalbed methane (CO2-ECBM) test will store up to 20,000 tons of carbon dioxide in a stacked coal reservoir in southwest Virginia. The test involves two phases of CO2 injection operations. Phase I was conducted from July 2, 2015 to April 15, 2016, and injected a total of 10, 601 tons of CO2. After a reservoir soaking period of seven months, Phase II is scheduled to begin Fall 2016. The design of the monitoring program for the test considered several site-specific factors, including a unique reservoir geometry, challenging surface terrain, simultaneous CBM production activities which complicate the ability to attribute signals to sources. A multi-scale approach to the monitoring design incorporated technologies deployed over different, overlapping spatial and temporal scales selected for the monitoring program include dedicated observation wells, CO2 injection operations monitoring, reservoir pressure and temperature monitoring, gas and formation water composition from offset wells tracer studies, borehole liquid level measurement, microseismic monitoring, surface deformation measurement, and various well logs and tests. Integrated interpretations of monitoring results from Phase I of the test have characterized enhanced permeability, geomechanical variation with depth, and dynamic reservoir injectivity. Results have also led to the development of recommended injection strategy for CO2-ECBM operations. The work presented here describes the development of the monitoring program, including design considerations and rationales for selected technologies, and presents monitoring results and interpretations from Phase I of the test.
Ph. D.

The continuous rising of anthropogenic emission into the atmosphere as a consequence of industrial growth is becoming uncontrollable, which causes heating up the atmosphere and changes in global climate. Therefore, CO2 emission becomes a big problem and key issue in environmental concerns. There are several options discussed for reducing the amount of CO2 emitted into the atmosphere. CO2 sequestration is one of these options, which involves the capture of CO2 from hydrocarbon emission sources, e.g. power plants, the injection and storage of CO2 into deep geological formations, e.g. depleted oil reservoirs. The complexity in the structure of geological formations and the processes involved in this method necessitates the use of numerical simulations in revealing the potential problems, determining feasibility, storage capacity, and life span credibility. Field K having 32o API gravity oil in a carbonate formation from southeast Turkey was studied. Field K was put on production in 1982 and produced until 2006, which was very close to its economic lifetime. Thus, it was considered as a candidate for enhanced oil recovery and CO2 sequestration. Reservoir rock and fluid data was first interpreted with available well logging, core and drill stem test data. Monte Carlo simulation was used to evaluate the probable reserve that was 7 million STB, original oil in place (OOIP). The data were then merged into CMG/STARS simulator. History matching study was done with production data to verify the results of the simulator with field data. After obtaining a good match, the different scenarios were realized by using the simulator. From the results of simulation runs, it was realized that CO2 injection can be applied to increase oil recovery, but sequestering of high amount of CO2 was found out to be inappropriate for field K. Therefore, it was decided to focus on oil recovery while CO2 was sequestered within the reservoir. Oil recovery was about 23% of OOIP in 2006 for field K, it reached to 43 % of OOIP by injecting CO2 after defining production and injection scenarios, properly.

Numerical modelling of subsurface processes, such as geotechnical, geohydrological or geothermal applications requires a realistic description of fluid parameters in order to obtain plausible results. Particularly for gases, the properties of a fluid strongly depend on the primary variables of the simulated systems, which lead to non-linerarities in the governing equations. This thesis describes the development, evaluation and application of a numerical model for non-isothermal flow processes based on thermodynamic principles. Governing and constitutive equations of this model have been implemented into the open-source scientific FEM simulator OpenGeoSys. The model has been verified by several well-known benchmark tests for heat transport as well as for single- and multiphase flow. To describe physical fluid behaviour, highly accurate thermophysical property correlations of various fluids and fluid mixtures have been utilized. These correlations are functions of density and temperature. Thus, the accuracy of those correlations is strongly depending on the precision of the chosen equation of state (EOS), which provides a relation between the system state variables pressure, temperature, and composition. Complex multi-parameter EOSs reach a higher level of accuracy than general cubic equations, but lead to very expansive computing times. Therefore, a sensitivity analysis has been conducted to investigate the effects of EOS uncertainties on numerical simulation results. The comparison shows, that small differences in the density function may lead to significant discrepancies in the simulation results. Applying a compromise between precision and computational effort, a cubic EOS has been chosen for the simulation of the continuous injection of carbon dioxide into a depleted natural gas reservoir. In this simulation, real fluid behaviour has been considered. Interpreting the simulation results allows prognoses of CO2 propagation velocities and its distribution within the reservoir. These results are helpful and necessary for scheduling real injection strategies
Für die numerische Modellierung von unterirdischen Prozessen, wie z. B. geotechnische, geohydrologische oder geothermische Anwendungen, ist eine möglichst genaue Beschreibung der Parameter der beteiligten Fluide notwendig, um plausible Ergebnisse zu erhalten. Fluideigenschaften, vor allem die Eigenschaften von Gasen, sind stark abhängig von den jeweiligen Primärvariablen der simulierten Prozesse. Dies führt zu Nicht-linearitäten in den prozessbeschreibenden partiellen Differentialgleichungen. In der vorliegenden Arbeit wird die Entwicklung, die Evaluierung und die Anwendung eines numerischen Modells für nicht-isotherme Strömungsprozesse in porösen Medien beschrieben, das auf thermodynamischen Grundlagen beruht. Strömungs-, Transport- und Materialgleichungen wurden in die open-source-Software-Plattform OpenGeoSys implementiert. Das entwickelte Modell wurde mittels verschiedener, namhafter Benchmark-Tests für Wärmetransport sowie für Ein- und Mehrphasenströmung verifiziert. Um physikalisches Fluidverhalten zu beschreiben, wurden hochgenaue Korrelationsfunktionen für mehrere relevante Fluide und deren Gemische verwendet. Diese Korrelationen sind Funktionen der Dichte und der Temperatur. Daher ist deren Genauigkeit von der Präzision der verwendeten Zustandsgleichungen abhängig, welche die Fluiddichte in Relation zu Druck- und Temperaturbedingungen sowie der Zusammensetzung von Gemischen beschreiben. Komplexe Zustandsgleichungen, die mittels einer Vielzahl von Parametern an Realgasverhalten angepasst wurden, erreichen ein viel höheres Maß an Genauigkeit als die einfacheren, kubischen Gleichungen. Andererseits führt deren Komplexität zu sehr langen Rechenzeiten. Um die Wahl einer geeigneten Zustandsgleichung zu vereinfachen, wurde eine Sensitivitätsanalyse durchgeführt, um die Auswirkungen von Unsicherheiten in der Dichtefunktion auf die numerischen Simulationsergebnisse zu untersuchen. Die Analyse ergibt, dass bereits kleine Unterschiede in der Zustandsgleichung zu erheblichen Abweichungen der Simulationsergebnisse untereinander führen können. Als ein Kompromiss zwischen Einfachheit und Rechenaufwand wurde für die Simulation einer enhanced gas recovery-Anwendung eine kubische Zustandsgleichung gewählt. Die Simulation sieht, unter Berücksichtigung des Realgasverhaltens, die kontinuierliche Injektion von CO2 in ein nahezu erschöpftes Erdgasreservoir vor. Die Interpretation der Ergebnisse erlaubt eine Prognose über die Ausbreitungsgeschwindigkeit des CO2 bzw. über dessen Verteilung im Reservoir. Diese Ergebnisse sind für die Planung von realen Injektionsanwendungen notwendig

En tant que géoscientifique dans le domaine de l’Exploration pétrolière et gazière depuis une vingtaine d’années, mes fonctions professionnelles m’ont permis d’effectuer différents travaux de recherche sur la thématique de la gestion des risques et des incertitudes. Ces travaux de recherche se situent sur l’ensemble de la chaîne d’analyse Exploration, traitant de problématiques liées à l’acquisition et au traitement sismique, jusqu’au placement optimal de forages d’exploration. Un volet plus poussé de mes travaux s’est orienté sur la gestion des incertitudes géophysiques en Exploration pétrolière, là où l’incertitude est la plus importante et paradoxalement la moins travaillée.On peut regrouper mes travaux de recherche en trois grands domaines qui suivent les grandes étapes du processus Exploration : le traitement sismique, leur interprétation, et enfin l'analyse et l'extraction des différentes incertitudes qui vont nous permettre de calculer les volumes d’hydrocarbures en place et récupérables, ainsi que l’analyse de ses risques associés. L’ensemble des travaux de recherche ont été appliqués avec succès sur des cas d’études opérationnelles. Après avoir introduit quelques notions générales et détaillé les grandes étapes du processus Exploration et leur lien direct avec ces problématiques, je présenterai quatre grands projets de recherche sur un cas d’étude algérien
In the last 20 years, I have been conducting various research projects focused on the management of risks and uncertainties in the petroleum exploration domain. The various research projects detailed in this thesis are dealing with problematics located throughout the whole Exploration and Production chain, from seismic acquisition and processing, until the optimal exploration to development wells placement. Focus is made on geophysical risks and uncertainties, where these problematics are the most pronounced and paradoxically the less worked in the industry. We can subdivide my research projects into tree main axes, which are following the hydrocarbon exploration process, namely: seismic processing, seismic interpretation thanks to the integration with various well informations, and eventually the analysis and extraction of key uncertainties, which will be the basis for the optimal calculation of in place and recoverable volumes, in addition to the associated risk analysis on a given target structure. The various research projects that are detailed in this thesis have been applied successfully on operational North Africa and North Sea projects. After introducing risks and uncertainty notions, we will detail the exploration process and the key links with these issues. I will then present four major research projects with their theoretical aspects and applied case study on an Algerian asset

Coal bed methane (CBM) is one of the world’s fastest growing unconventional gas resources and offers the potential for much cleaner power than from traditional coal. However, low productivity index in coal bed methane reservoirs places them on the margin of economic efficiency. One of the key technological hurdles affecting the productivity index in CBM reservoirs is the extremely low permeability of coal’s natural cleat and fracture system. Thus, development of new techniques for enhancing coal cleat permeability is essential for cost-effective gas production from CBM reservoirs. The hydraulic fracturing is the most widely used CBM well stimulation method; however, the hydraulic fracturing is often restricted by the environmental regulations. Besides, the available injection power may not be sufficient to fracture the well. The way around this problem is stimulation of a natural cleat system keeping the reservoir pressure below the fracturing pressure. The main objective of this study is to develop a new well stimulation technology utilizing graded proppant injection to allow sequential filling of both distant and near-well fractures. This mechanism leads to a significant enhancement of permeability and, therefore, improved well productivity. Mathematical modelling and experimental studies are conducted for stimulation of natural cleat system in coal bed methane reservoirs. The aim of this work is to determine an optimum injection schedule, i.e. the timely dependencies of the injected proppant size and concentration that avoids fracture closure during production stage and provides minimum hydraulic resistance in the system of fractures plugged by proppant particles. The laboratory tests on one dimensional injection of different size particles into coal cores have been conducted under different effective stress conditions. Calculations of electrostatic interactions result in determining the physicochemical conditions, favourable for particle-particle and particle-coal repulsion. The repulsion prevents: particle attachment to the coal surface, particle agglomeration and consequent formation damage due to external and internal cake formation. Particle placement with low-salinity water, which promotes the repulsion, improves the coal permeability. A laboratory-based mathematical model is developed to describe the proppantfree water injection stage; capture kinetics of proppant particles in the natural fractures and calculation of an optimal injection schedule. The analytical model is derived for exponential stress-permeability relationship and accounting for permeability variation outside the stimulated zone. Field case studies show that the productivity index can be significantly increased by applying the stimulation technology developed in this thesis. The sensitivity analysis of well index shows that the most influential parameters are the stimulated zone size, injection pressure and the cleat system compressibility. The above laboratory study, mathematical modelling and the field-scale predictions allow recommending the developed technology of graded proppant injection for improving gas recovery from Coal bed methane reservoirs.
Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2015

1. Objective: The objective of this research has been to develop more reliable models to predict the miscibility and interactions between CO₂ or green-house gas (GHG) and oil (dead and live oils) over a wider range of conditions, based on data from different site sources, considering all the major variables affecting each modelled parameter, and for different injected gas compositions. The Genetic algorithm (GA), an artificial intelligence technique based on the Darwinian theory of evolution that mimics some of the natural processes in living organisms, was used to develop these models, based on GA software that has been developed in this work (as a modelling technique). While applications of GA have been used recently in the mathematical and computer sciences, its applications in the petroleum engineering, especially EOR research, have been limited. 2. Motivation to Investigate the Potential of GA-based Models: The detrimental effects of CO₂ and/or GHG emissions from various industrial and human/activity sources on the environment are a major concern worldwide. This has resulted in an intensive global R&D effort to lower or mitigate the damaging impact of GHG on the environment. One potentially attractive and effective means of lowering the GHG emissions could be to capture them from their major sources of emissions and then sequester them in depleted oil and gas reservoirs while also enhancing oil recovery. Typically, a GHG stream, also referred to as "flue gas", contains high percentages of CO₂ in addition to other gases, notably, N₂, NOₓ and SOₓ. The presence of high CO₂ content in the flue gas, in particular, could make this option potentially viable, provided the miscibility and interaction properties between the injected gas and reservoir fluids are favorable. Therefore, it is critical to ascertain the likely miscibility and interactions parameters between the injected gas (CO₂ or flue gas) and oil at different conditions to determine the optimal miscibility and interaction conditions that contribute to oil viscosity reduction and oil swelling. They in turn enhance oil recovery through improved gas flooding process performance due to higher oil mobility, volumetric sweep efficiency, and relative permeability to oil. Often miscibility and interactions between injected gases and oils are established through "experimental methods", "new mathematical models" based on phase equilibria data and equations of state (EOS), and available "published models". Experimental methods are time-consuming and costly. Moreover, they can handle only limited conditions. Mathematical models require availability of a considerable amount of reservoir fluid composition data, which may not be available most of the time. Although, the published models are simpler and faster to use, one must however recognise that most of these models were developed and validated based on limited data ranges from site-specific conditions. Therefore, their applications cannot be generic. Another noteworthy point is that most of the interactions models have been developed using dead oil data and pure CO₂ as an injected gas. Hence, they do not perform well for a wider range of live oils, as well as injected flue gases, which contain different components besides CO₂. Consequently, there is a need to have more reliable miscibility and interaction models, which can handle a much wider range of conditions and different data sources. Also, these models should be able to consider all the major variables, different injected gas compositions, and live oil in addition to dead oil. 3. GA-based Models Developed in This Research: -- GA-based model for more reliable prediction of minimum miscibility pressure (MMP) between reservoir oil and CO₂: This model recognised the major variables affecting MMP (reservoir temperature, MWc₅₊ , and volatiles and intermediates compositions). It has been successfully validated with published experimental data and compared to common models in the literature. It is noted that GA-based CO₂-oil MMP offered the best match with the lowest error and standard deviation. -- GA-based flue gas-oil MMP model: For this model, the MMP was regarded as a function of the injected gas solubility into oil, which in turn is related to the injected gas critical properties (pseudocritical temperature and pressure) besides reservoir temperature and oil composition. A critical temperature modification factor was also used in developing this model. The GA-based model has also been successfully validated against published experimental data and compared to several models in the literature. It yielded the best match with the lowest average error and standard deviation. Moreover, unlike other models, it can be used more reliably for gases with higher N₂ (up to 20 mole%) and different non-CO₂ components (e.g., H₂S, N₂, SOₓ, O₂, and C₁-C₄) with higher ratio (up to 78 mole%). -- GA-based CO₂-oil physical properties models: These models have been developed to predict CO₂ solubility, impact on the oil swelling factor, CO₂-oil density, and CO₂-oil viscosity for both dead and live oils. These models recognised the major variables that affect each physical property and also properly address the effects of CO2 liquefaction pressure and oil molecular weight (MW). These models have been successfully validated with published experimental data and have been compared against several widely used models. The GA-based CO₂-oil properties models yielded more accurate predictions with lower errors than other models that have been tested. Furthermore, unlike the other tested models, which are applicable to only limited data ranges and conditions, GA-based models can be applied over a wider data range and conditions. -- GA-based flue gas-oil physical properties models: These models predict flue gas-oil properties such as, flue gas solubility, impact on the oil swelling factor, and flue gas-oil density and viscosity while recognising all the major variables affecting each property. Also, the GA-based models recognised the different injected flue gas compositions. These models have been successfully validated with published experimental data and have also been compared against other commonly reported CO₂-oil models, which are often used for flue gas-oil physical properties prediction. The GA-based models consistently yielded a lower prediction error than the models that have been tested. Furthermore, unlike other models, which are applicable only over limited data ranges and conditions, GA-based models can be valid over a wider range of data under various conditions. All the above-mentioned models, developed in this research, are particularly useful when experimental data are lacking and the project financial situation is a concern. In addition, these models can be useful as a fast track gas flooding project screening guide. Also, they can easily be incorporated into a reservoir simulator for CO₂ or flue gas flooding design and simulation. Furthermore, they can serve as yet another useful tool to design optimal and economical experimental test protocols to etermine the miscibility and interactions between the injected CO₂ or flue gas and oils in gas flooding processes.
http://proxy.library.adelaide.edu.au/login?url= http://library.adelaide.edu.au/cgi-bin/Pwebrecon.cgi?BBID=1236741
Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2006.

This paper establishes Low-Tension-Gas (LTG) as a method for sub-miscible tertiary recovery in tight sandstone and carbonate reservoirs. The LTG process involves the use of a low foam quality surfactant-gas solution to mobilize and then displace residual crude after waterflood. It replicates the existing Alkali-Surfactant-Polymer (ASP) process in its creation of an ultra-low oil-water interfacial tension (IFT) environment for oil mobilization, but instead supplements the use of foam over polymer for mobility control. By replacing polymer with foam, chemical Enhanced Oil Recovery (EOR) methods can be expanded into sub-30 mD formations where polymer is impractical due to plugging, shear, or the requirement to use a low molecular weight polymer. Overall results indicate favorable mobilization and displacement of residual crude oil in both tight carbonate and tight sandstone reservoirs. Tertiary recovery of 75-95% ROIP was achieved for cores with 2-15 mD permeability, with similar oil bank and other ASP analogous process attributes observed. Moreover, similar recovery was achieved during testing at high initial oil saturation (56%), indicating high process tolerance to oil saturation and potential application for implementation at secondary recovery. In addition, a number of tools and relations were developed to improve the predictive relationship between observed coreflood properties and actual mobilization or displacement mechanisms which impact reservoir-scale flooding. These relations include qualitative dispersion comparison and calculation of in-situ gas saturation, macroscopic mobility ratio at the displacement fronts, and apparent viscosity of injected fluids. These tools were validated through use of reference gas and surfactant floods and indicate that stable macroscopic displacement can be achieved through LTG flooding in tight formations. Furthermore, to better reflect actual reservoir conditions where localized fractional flow of gas can vary substantially depending on mixing or gravity phenomenon, two additional sets of data were developed to empirically model behavior. Through testing of LTG co-injection at a number of discrete fractional flow values over a wide range, recovery was shown to achieve a relative maximum at 50% gas fractional flow which also corresponded with optimal observed mobility control as measured by the previously established tools. Likewise, through testing of surfactant-alternating-gas (SAG) injection cycling, displacement and overall recovery were shown to be improved versus reference co-injection flooding. Finally, by comparing the observed displacement and mobility data among co-injection and surfactant-alternating-gas floods, a new displacement mechanism is introduced to better relate actual displacement conditions with observed macroscopic mobility data. This mechanism emphasizes the role of liquid rate in actual displacement processes and a mostly static gas saturation (independent of gas rate) in altering liquid relative permeability and diverting injected liquid into lower permeability zones.
text

The inhibitor and steam injection methods have been examined using a laboratory-prepared methane hydrate bearing sediment. New experimental apparatuses have been designed and constructed. In the case of inhibitor injection, the measurement of gas production vs. time suggested that the inhibitor increased dissociation rate. Core temperature decreased upon the inhibitor injection, in contrast to that in the case of pure water injection. The observed pressure differentials between the inlet and outlet of the core sample suggest that the inhibitor effectively prevented the hydrate reformation within the dissociating core sample. In the case of steam injection coupled with depressurization, it can be seen that the effect of steam (or hot water) injection was clear in the later stage of dissociation, compared with that in the case of depressurization alone. The inner (core) temperature change indicates that the coupling of depressurization and steam injection induces MH dissociation from upstream and downstream to the center of the sample. However, it starts from an upstream region and continues downstream steadily in the case of steam (hot water) injection alone.

碩士
國立成功大學
資源工程學系
107
Gas hydrates are solid ice-like component composed of water molecules and small size gas molecules, which exist in the condition of high pressure and low temperature. Due to the stable condition of hydrate, it is an unconventional gas resources that widely spread over deep oceanic sediments and permafrost regions. According to the exploration, there are also gas hydrate resources in southwestern Taiwan. There are 3 classes of gas hydrate deposits. Because of the existent of free gas zone beneath the hydrate layer, the class 1 gas hydrate is considered to be the most profitable production target. Most of the marine hydrate resources are found in unconsolidated sedimentary formation. Therefore, there is a risk of potential geohazard caused by seafloor subsidence and hydrate dissociation during the hydrate deposit production. Targeting at the marine class 1 hydrate deposits, the purpose of this study is to establish a safety operation strategy to produce the gas resource from the free gas zone. The CO2 EGR strategy is applied to stabilize the reservoir pressure preventing seafloor subsidence during the gas production. CMG STARS simulator is used to calculate the reservoir production and the geomechanics behavior of the formation. In this study, different operation strategies are tested and discussed to figure out the relevance between the operation methods and the production performances. The results suggest that the CO2¬ breakthrough control is essential to the application of CO2 EGR strategy. Later CO2¬ breakthrough results in greater gas production. By applying CO2 injection delay or lower injection pressure, the production can be extended and result in higher production with more severe situation of formation subsidence and hydrate dissociation. Allowing more CO2 content in produced gas can benefit the overall production without subsidence.

The aim of this thesis is to investigate innovate approaches that can help to improve methane recovery and production rate from coalbed methane (CBM) reservoirs. The results of two following subjects are presented and discussed. First, thermally enhanced gas recovery from gassy coalbeds is introduced. Second, an integrated reservoir simulation-optimization framework is developed and employed to optimize infill well locations across coalbed reservoirs. When coalbed methane and geothermal activities coexist in the same field, coalbeds can be thermally treated prior to the gas production using available underground geothermal resources. Feasibility of this method is investigated both using methane sorption tests on Australian coal samples at different temperatures and also reservoir simulation. The impact of temperature elevation on methane sorption and diffusion in coal is investigated by running sorption experiments on two the Australian coal samples using a manometric adsorption apparatus. Experiments are performed to indicate that how the difference between original reservoir pressure and critical desorption pressure is decreased at elevated reservoir temperatures. Lower pressure gradient is required to extract methane from coalbed when it is thermally treated prior to gas production. Following the experimental study, the feasibility of thermally enhanced gas production from coalbeds is studied by coupling of coalbed methane and thermal simulators. The coalbed methane simulator of Computer Group Modelling (CMG) and the thermal simulator of CMG known as STARS are loosely coupled to study the effect of temperature elevation on total gas and water production. Both gas rate and ultimate gas recovery from the reservoir are increased by thermal operation. In the second part of this thesis, an integrated reservoir simulation-optimization framework is developed to intelligently obtain locations of new infill wells in a way to maximize profitability of the infill plan. This framework consists of a reservoir flow simulator (Eclipse E100), an optimization method (genetic algorithm), and an economic objective function. The objective function in this framework is to maximize discounted net cash flow of infill project. The importance of optimization is magnified when cost of water treatment is increased. When optimization approach is compared with standard five spot pattern well arrangements, the impact of water treatment cost is observed. When cost of water treatment is high, there is a large difference between the profit of the infill project calculated using the optimization approach and the standard five spot pattern. Simulation results indicate that at higher cost of water treatment, infill wells are preferably located either on the front of the water depletion zone or close to existing wells. On the other hand, when water treatment cost is low, infill wells are located in virgin sections of the coalbed where both gas content and cleat water saturation are high.
Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2013

Oil production from EOR and waterflood processes supplies a considerable amount of the world's oil production. Therefore, the screening and selection of the best EOR process becomes important. Numerous steps are involved in evaluating EOR methods for field applications. Binary screening guides in which reservoirs are selected on the basis of reservoir average rock and fluid properties are consulted for initial determination of applicability. However, quick quantitative comparisons and performance predictions of EOR processes are more complicated and important than binary screening that are the objectives of EOR forecasting. Forecasting (predicting) the performance of EOR processes plays an important role in the study, design and selection of the best method for a particular reservoir or a collection of reservoirs. In EOR forecasting, we look for finding ways to get quick quantitative results of the performance of different EOR processes using analytical model/s before detailed numerical simulations of the reservoirs under study. Although numerical simulation of the reservoirs is widely used, there are significant obstacles that restrict its applicability. Lack of necessary reservoir data and time consuming computations and analyses can be barriers even for history matching and/or predicting EOR/waterflood performance of one reservoir. There are different forecasting (predictive) models for evaluation of different secondary/tertiary recovery methods. However, lack of a general purpose EOR/waterflood forecasting model is unsatisfactory because any differences in results can be caused by differences in the model rather than differences in the processes. As the main objective of this study, we address this deficiency by presenting a novel and robust analytical-base general EOR and waterflood forecasting model/tool (UTF) that does not rely on conventional numerical simulation. The UTF conceptual model is based on the fundamental law of material balance, segregated flow and fractional flux theories and is applied for both history matching and forecasting the EOR/waterflood processes. The forecasting model generates the key results of isothermal EOR and waterflooding processes including variations of average oil saturation, recovery efficiency, volumetric sweep efficiency, oil cut and oil rate with real or dimensionless time. The forecasting model was validated against field data and numerical simulation results for isothermal EOR and waterflooding processes. The forecasting model reproduced well (R2> 0.8) all of the field data and reproduced the simulated data even better. To develop the UTF for forecasting when there is no injection/production history data, we used experimental design and numerical simulation and successfully generated the in-situ correlations (response surfaces) of the forecasting model variables. The forecasting model variables were proven to be well correlated to reservoir/recovery process variables and can be reliably used for forecasting. As an extension to the abilities of the forecasting model, these correlations were used for prediction of volumetric sweep efficiency and missing/dynamic pore volume of EOR and waterflooding processes.
text

Foam-assisted low interfacial tension and foam-improved sweep efficiency are attractive enhanced oil recovery (EOR) methods with numerous studies and researches have been conducted in the past few decades. For example, CO₂-Enhanced Oil Recovery (CO₂-EOR) is very efficient in terms of oil displacement. However, due to the low viscosity of super critical CO₂, the process usually suffers from poor sweep efficiency. One method of increasing sweep efficiency in CO₂-EOR has been identified through the use of surfactants to create "foams" or more correctly CO₂-in-water (C/W) macroemulsions. Polymer flooding techniques such as Alkali -- Polymer (AP), Surfactant -- Polymer (SP), and Alkali -- Surfactant -- Polymer (ASP) have been the only proven chemical EOR method in sandstone reservoirs with many successful pilot tests and field projects. However, the use of polymer is limited in carbonates due to unfavorable conditions related to natural characteristics of this type of lithology. In this case, foam-assisted EOR, specifically Alkali -- Surfactant -- Gas (ASG) process, can be an alternative for polymer flooding. It is a fact that large amount of the world's oil reserves resides in carbonate reservoirs. Therefore, an increase in oil recovery from carbonates would help meet the world's increasing energy demand. This study consists of two parts: (1) the development of new surfactant for creating CO₂ -- in -- water macroemulsions for improving sweep efficiency in CO₂ -- EOR processes; (2) systematic study of ASG method as a novel EOR technique and an alternative for polymer flooding in carbonate reservoirs. Both studies are related to the use of foam as a mobility control agent. In the first part, the design and synthesis of twin tailed surfactants for use at the CO₂/water interface is discussed. The hydrohobes for these surfactants are synthesized from epichlorohydrin and an excess alcohol. Subsequent ethoxylation of the resulting symmetrical dialkyl glycerin yields the water soluble dual tailed surfactants. The general characteristics of these surfactants in water are described. A comparison is carried out between twin-tailed dioctylglycerine surfactants and linear secondary alcohol surfactant based on results from a core flood. The results show that even above the cloud point of the surfactants, the twin tailed surfactants create a significant mobility reduction, likely due to favorable partitioning into the CO₂ phase. The data covers surfactant structures designed specifically for the CO₂-water interface and can be used by producers and service companies in designing new CO₂-floods, especially in areas that might not have been considered due to problems with reservoir heterogeneity. Second part contains a systematic study of ASG process on carbonate rocks through a series of experiments. The purpose is to demonstrate the performance as well as the potential of ASG as a new EOR technique. In this study, basic concepts in chemical EOR are presented, while the design of chemical formulation, phase behavior, and the role of foam are discussed in details. Experimental results showed relatively good recovery, low surfactant retention. However, pressure drop during chemical injections were high, which indicates the formation of both strong foam and viscous microemulsion at the displacement front when surfactant starts solubilizing oil. Overall, ASG showed good performance on carbonate rocks. Optimization can be made on surfactant formula to form less viscous microemulsion and therefore improve efficiency of the process.
text

Canada and Venezuela contain massive unconventional oil deposits accounting for over two thirds of newly discovered proven oil reserves since 2002. Canada, primarily in northern Alberta province, has between 1.75 and 1.84 trillion barrels of hydrocarbon resources that as of 2013 are obtained approximately equally through surface extraction or enhanced oil recovery (EOR) (World Energy Council, 2010). Due to their depth and viscosity, thermal based EOR will increasingly be responsible for producing the vast quantities of bitumen residing in Canada’s Athabasca, Cold Lake, and Peace River formations. Although the internationally accepted 174-180 billion barrels recoverable ranks Canada third globally in oil reserves, it represents only a 9-10% average recovery factor of its very high viscosity deposits (World Energy Council, 2010). As thermal techniques are refined and improved, in conjunction with methods under development and integrating elements of existing but currently separate processes, engineers and geoscientists aim to improve recovery rates and add tens of billions of barrels of oil to Canada’s reserves (Cenovus Energy, 2013). The Government of Canada estimates 315 billion barrels recoverable with the right combination of technological improvements and sustained high oil prices (Government of Canada, 2013). Much uncertainty and skepticism surrounds how this 75% increase is to be accomplished. This document entails a thorough analysis of standard and advanced EOR techniques and their potential incremental impact in Canada’s bitumen deposits. Due to the extraordinary volume of hydrocarbon resources in Canada, a small percentage growth in ultimate recovery satisfies years of increased petroleum demand from the developing world, affects the geopolitics within North America and between it and the rest of the world, and provides material benefits to project economics. This paper details the enhanced oil recovery methods used in the oil sands deposits while exploring new developments and their potential technical and economic effect. CMG Stars reservoir simulation is leveraged to test both the feasible recoveries of and validate the physics behind select advanced techniques. These technological and operational improvements are aggregated and an assessment produced on Canada’s total recoverable petroleum reserves. Canada has, by far, the largest bitumen recovery operation in the world (World Energy Council, 2010). Due to its resource base and political environment, the nation is likely to continue as the focus point for new developments in thermal EOR. Reservoir characteristics and project analysis are thus framed using Canada and its reserves.
text

Highly fractured and vuggy oil reservoirs represent a challenge for enhanced oil recovery (EOR) methods. The fractured networks provide flow paths several orders of magnitude greater than the rock matrix. Common enhanced oil recovery methods, including gases or low viscosity liquids, are used to channel through the high permeability fracture networks causing poor sweep efficiency and early breakthrough. The purpose of this research is to determine the feasibility of using foam in highly fractured reservoirs to produce oil-rich zones. Multiple surfactant formulations specifically tailored for a distinct oil type were analyzed by aqueous stability and foam stability tests. Several core floods were performed and targeted effects such as foam quality, injection rate, injection type, permeability, gas saturation, wettability, capillary pressure, diffusion, foam squeezing, oil flow, microemulsion flow and gravity segregation. Ultimately, foam was successfully propagated under various core geometries, initial conditions and injections methods. Consequently, fluids were able to divert to unswept matrix and improve the ultimate oil recovery.
text

A numerical reservoir model was created to optimize CO₂ Huff-and-Puff operations in the Bakken Shale. Huff-and-Puff is an enhanced oil recovery treatment in which a well alternates between injection, soaking, and production. Injecting CO₂ into the formation and allowing it to “soak” re-pressurizes the reservoir and improves oil mobility, boosting production from the well. A compositional reservoir simulator was used to study the various design components of the Huff-and-Puff process in order to identify the parameters with the largest impact on recovery and understand the reservoir’s response to cyclical CO₂ injection. It was found that starting Huff-and-Puff too early in the life of the well diminishes its effectiveness, and that shorter soaking periods are preferable over longer waiting times. Huff-and-Puff works best in reservoirs with highly-conductive natural fracture networks, which allow CO₂ to migrate deep into the formation and mix with the reservoir fluids. The discretization of the computational domain has a large impact on the simulation results, with coarser gridding corresponding to larger projected recoveries. Doubling the number of hydraulic fractures per stage results in considerably greater CO₂ injection requirements without proportionally larger incremental recovery factors. Incremental recovery from CO₂ Huff-and-Puff appears to be insufficient to make the process commercially feasible under current economic conditions. However, re-injecting mixtures of CO₂ and produced hydrocarbon gases was proven to be technically and economically viable, which could significantly improve profit margins of Huff-and-Puff operations. A substantial portion of this project involved studying alternative numerical methods for modeling hydraulically-fractured reservoir models. A domain decomposition technique known as mortar coupling was used to model the reservoir system as two individually-solved subdomains: fracture and matrix. A mortar-based numerical reservoir simulator was developed and its results compared to a tradition full-domain finite difference model for the Cinco-Ley et al. (1978) finite-conductivity vertical fracture problem. Despite some numerical issues, mortar coupling closely matched Cinco-Ley et al.'s (1978) solution and has potential applications in complex problems where decoupling the fracture-matrix system might be advantageous.
text

This work investigates the performance of CO₂ soluble surfactants used for CO₂ foam flooding in fractured carbonate reservoirs. Oil recovery associated with the reduction of CO₂ mobility in fractures is assessed by monitoring oil saturation and pressure drops during injection of CO₂ with aqueous surfactant solution in artificially fractured carbonate cores. Distinct novel CO₂ soluble surfactants are evaluated as well as a conventional surfactant. Water flooding and pure CO₂ injection are conducted as baseline. Characterization of fluids and rock are also reported which include Amott test, oil phase behavior and slim tube test. Transport and thermodynamic properties of surfactant and supercritical CO₂ are used to evaluate the process on a core scale using a commercial reservoir simulator.
text

This dissertation focused on the development of mass spectrometric methodologies, separation techniques, and engineered devices for the optimal analysis of complex mixtures relevant to the energy sector, such as alternative fuels, petroleum-based fuels, crude oils, and processed base oils. Mass spectrometry (MS) has been widely recognized as a powerful tool for the analysis of complex mixtures. In complex energy samples, such as petroleum-based fuels, alternative fuels, and oils, high-resolution MS alone may not be sufficient to elucidate chemical composition information. Separation before MS analysis is often necessary for such highly complex energy samples. For volatile samples, in-line two-dimensional gas chromatography (GC×GC) can be used to separate complex mixtures prior to ionization. This technique allows for a more accurate determination of the compounds in a mixture, by simplifying the mixture into its components prior to ionization, separation based on mass-to-charge ratio (m/z), and detection. A GC×GC coupled to a high-resolution time-of-flight MS was utilized in this research to determine the chemical composition of alternative aviation fuels, a petroleum-based aviation fuel, and alternative aviation fuel candidates and blending components as well as processed base oils.

Additionally, as the cutting edge of science and technology evolve, methods and equipment must be updated and adapted for new samples or new sector demands. One such case, explored in this dissertation, was the validation of an updated standardized method, ASTM D2425 2019. This updated standardized method was investigated for a new instrument and new sample type for a quadrupole MS to analyze a renewable aviation fuel. Lastly, the development and evaluation of a miniaturized coreflood device for analyzing candidate chemically enhanced oil recovery (cEOR) formulations of brine, surfactant(s), and polymer(s) was conducted. The miniaturized device was used in the evaluation of two different cEOR formulations to determine if the components of the recovered oil changed.

Numerical modelling of subsurface processes, such as geotechnical, geohydrological or geothermal applications requires a realistic description of fluid parameters in order to obtain plausible results. Particularly for gases, the properties of a fluid strongly depend on the primary variables of the simulated systems, which lead to non-linerarities in the governing equations. This thesis describes the development, evaluation and application of a numerical model for non-isothermal flow processes based on thermodynamic principles. Governing and constitutive equations of this model have been implemented into the open-source scientific FEM simulator OpenGeoSys. The model has been verified by several well-known benchmark tests for heat transport as well as for single- and multiphase flow. To describe physical fluid behaviour, highly accurate thermophysical property correlations of various fluids and fluid mixtures have been utilized. These correlations are functions of density and temperature. Thus, the accuracy of those correlations is strongly depending on the precision of the chosen equation of state (EOS), which provides a relation between the system state variables pressure, temperature, and composition. Complex multi-parameter EOSs reach a higher level of accuracy than general cubic equations, but lead to very expansive computing times. Therefore, a sensitivity analysis has been conducted to investigate the effects of EOS uncertainties on numerical simulation results. The comparison shows, that small differences in the density function may lead to significant discrepancies in the simulation results. Applying a compromise between precision and computational effort, a cubic EOS has been chosen for the simulation of the continuous injection of carbon dioxide into a depleted natural gas reservoir. In this simulation, real fluid behaviour has been considered. Interpreting the simulation results allows prognoses of CO2 propagation velocities and its distribution within the reservoir. These results are helpful and necessary for scheduling real injection strategies.
Für die numerische Modellierung von unterirdischen Prozessen, wie z. B. geotechnische, geohydrologische oder geothermische Anwendungen, ist eine möglichst genaue Beschreibung der Parameter der beteiligten Fluide notwendig, um plausible Ergebnisse zu erhalten. Fluideigenschaften, vor allem die Eigenschaften von Gasen, sind stark abhängig von den jeweiligen Primärvariablen der simulierten Prozesse. Dies führt zu Nicht-linearitäten in den prozessbeschreibenden partiellen Differentialgleichungen. In der vorliegenden Arbeit wird die Entwicklung, die Evaluierung und die Anwendung eines numerischen Modells für nicht-isotherme Strömungsprozesse in porösen Medien beschrieben, das auf thermodynamischen Grundlagen beruht. Strömungs-, Transport- und Materialgleichungen wurden in die open-source-Software-Plattform OpenGeoSys implementiert. Das entwickelte Modell wurde mittels verschiedener, namhafter Benchmark-Tests für Wärmetransport sowie für Ein- und Mehrphasenströmung verifiziert. Um physikalisches Fluidverhalten zu beschreiben, wurden hochgenaue Korrelationsfunktionen für mehrere relevante Fluide und deren Gemische verwendet. Diese Korrelationen sind Funktionen der Dichte und der Temperatur. Daher ist deren Genauigkeit von der Präzision der verwendeten Zustandsgleichungen abhängig, welche die Fluiddichte in Relation zu Druck- und Temperaturbedingungen sowie der Zusammensetzung von Gemischen beschreiben. Komplexe Zustandsgleichungen, die mittels einer Vielzahl von Parametern an Realgasverhalten angepasst wurden, erreichen ein viel höheres Maß an Genauigkeit als die einfacheren, kubischen Gleichungen. Andererseits führt deren Komplexität zu sehr langen Rechenzeiten. Um die Wahl einer geeigneten Zustandsgleichung zu vereinfachen, wurde eine Sensitivitätsanalyse durchgeführt, um die Auswirkungen von Unsicherheiten in der Dichtefunktion auf die numerischen Simulationsergebnisse zu untersuchen. Die Analyse ergibt, dass bereits kleine Unterschiede in der Zustandsgleichung zu erheblichen Abweichungen der Simulationsergebnisse untereinander führen können. Als ein Kompromiss zwischen Einfachheit und Rechenaufwand wurde für die Simulation einer enhanced gas recovery-Anwendung eine kubische Zustandsgleichung gewählt. Die Simulation sieht, unter Berücksichtigung des Realgasverhaltens, die kontinuierliche Injektion von CO2 in ein nahezu erschöpftes Erdgasreservoir vor. Die Interpretation der Ergebnisse erlaubt eine Prognose über die Ausbreitungsgeschwindigkeit des CO2 bzw. über dessen Verteilung im Reservoir. Diese Ergebnisse sind für die Planung von realen Injektionsanwendungen notwendig