Dissertations / Theses on the topic 'Natural gas Gas reservoirs. Thermodynamics'

Thesis (M.S.)--West Virginia University, 2009.
Title from document title page. Document formatted into pages; contains ix, 97 p. : ill. (some col.), col. map. Includes abstract. Includes bibliographical references.

In this study
gas production by depressurization method from a hydrate reservoir containing free gas zone below the hydrate zone is numerically modeled through 3 dimensional, 3 phase, non-isothermal reservoir simulation. The endothermic nature of hydrate decomposition requires modeling to be non-isothermal
hence energy balance equations must be employed in the simulation process. TOUGH-Fx, the successor of the well known multipurpose reservoir simulator TOUGH2 (Pruess [24]) and its very first module TOUGH-Fx/Hydrate, both developed by Moridis et.al [23] at LBNL, are utilized to model production from a theoretical hydrate reservoir, which is first studied by Holder [11] and then by Moridis [22], for comparison purposes. The study involves 2 different reservoir models, one with 30% gas in the hydrate zone (case 1) and other one with 30% water in the hydrate zone (case 2). These models are further investigated for the effect of well-bore heating. The prominent results of the modeling study are: &
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In case 1, second dissociation front develops at the top of hydrate zone and most substantial methane release from the hydrate occurs there. &
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In case 2 (hydrate-water in the hydrate zone), because a second dissociation front at the top of hydrate zone could not fully develop due to high capillary pressure acting on liquid phase, a structure similar to ice lens formation is observed. &
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Initial cumulative replenishment (first 5 years) and the replenishment rate (first 3.5 years) are higher for case 2 because, production pressure drop is felt all over the reservoir due to low compressibility of water and more hydrate is decomposed. Compared to previous works of Holder [11] and Moridis [22], amount of released gas contribution within the first 3 years of production is significantly low which is primarily attributed to the specified high capillary pressure function.

More than 120 depleted natural gas reservoirs in Alberta, Canada have been identified as potential sites for CO₂ storage at temperature and pressure conditions at which CO₂ may form gas hydrate. Reservoir simulations presented in the literature have demonstrated the feasibility of storing CO₂ in such reservoirs. In this thesis, the injection of CO₂ in a laboratory size reservoir (packed bed of silica particles) serving as a physical model for a depleted reservoir was studied. The hypothesis was that injecting CO₂ into the reservoir at gas hydrate formation conditions will be beneficial in terms of increased CO₂ storage density. It is noted that CO₂ is stored not only as hydrate but also some is dissolved in the residual pore water (not converted to hydrate) and some as a gas in the remaining pore space. The results indicate that hydrate formation enhances the CO₂ storage density. The work also demonstrated that substances like tapioca starch added to the water in small quantities (1 wt %) delayed the onset of hydrate nucleation in the earlier stage but subsequently more CO₂ was stored as hydrate compared to the tapioca starch-free systems. The delay in nucleation decreases the risk to form a hydrate plug in the injection system. The injection of the CO₂-rich mixture (90 mol % CO₂/10 mol % N₂), which is a typical composition of a flue gas after CO₂ capture process, into a reservoir with CH4 (simulating residual natural gas) was also studied in the laboratory reservoir. It was found that the total CO₂ storage density (in hydrate, gaseous and dissolved state) decreased from 143 kg/m³ (the CO₂ injection into a CH₄ free reservoir) to 119 kg/m³. Finally, relevant phase equilibrium data were obtained in a constant volume high pressure vessel and by calorimetry. The results were found to be in good agreement with thermodynamic model calculated values within ± 40 kPa and ± 0.2 K, respectively.
Applied Science, Faculty of
Chemical and Biological Engineering, Department of
Graduate

The objective of this work has been to study equilibrium and non equilibrium situations during high pressure gas processing operations with emphasis on utilization of the high reservoir pressure. The well stream pressures of some of the condensate and gas fields in the North Sea are well above 200 bar. Currently the gas is expanded to a specified processing condition, typically 40-70 bar, before it is recompressed to the transportation conditions. It would be a considerable environmental and economic advantage to be able to process the natural gas at the well stream pressure. Knowledge of thermodynamic- and kinetic properties of natural gas systems at high pressures is needed to be able to design new high pressure process equipment.

Nowadays, reactive absorption into a methyldiethanolamine (MDEA)solution in a packed bed is a frequently used method to perform acid gas treating. The carbon dioxide removal process on the Sleipner field in the North Sea uses an aqueous MDEA solution and the operation pressure is about 100 bar. The planed carbon dioxide removal process for the Snøhvit field in the Barents Sea is the use of an activated MDEA solution.

The aim of this work has been to study high-pressure effects related to the removal of carbon dioxide from natural gas. Both modelling and experimental work on high-pressure non-equilibrium situations in gas processing operations have been done.

Few experimental measurements of mass transfer in high pressure fluid systems have been published. In this work a wetted wall column that can operate at pressures up to 200 bar was designed and constructed. The wetted wall column is a pipe made of stainless steel where the liquid is distributed as a thin liquid film on the inner pipewall while the gas flows co- or concurrent in the centre of the pipe. The experiments can be carried out with a well-defined interphase area and with relatively simple fluid mechanics. In this way we are able to isolate the effects we want to study in a simple and effective way.

Experiments where carbon dioxide was absorbed into water and MDEA solutions were performed at pressures up to 150 bar and at temperatures 25 and 40°C. Nitrogen was used as an inert gas in all experiments.

A general non-equilibrium simulation program (NeqSim) has been developed. The simulation program was implemented in the object-oriented programming language Java. Effort was taken to find an optimal object-oriented design. Despite the increasing popularity of object-oriented programming languages such as Java and C++, few publications have discussed how to implement thermodynamic and fluid mechanic models. A design for implementation of thermodynamic, mass transfer and fluid mechanic calculations in an object-oriented framework is presented in this work.

NeqSim is based on rigorous thermodynamic and fluid mechanic models. Parameter fitting routines are implemented in the simulation tool and thermodynamic-, mass transfer- and fluid mechanic models were fitted to public available experimental data. Two electrolyte equations of state were developed and implemented in the computer code. The electrolyte equations of state were used to model the thermodynamic properties of the fluid systems considered in this work (non-electrolyte, electrolyte and weak-electrolyte systems).

The first electrolyte equation of state (electrolyte ScRK-EOS) was based on a model previously developed by Furst and Renon (1993). The molecular part of the equation was based on a cubic equation of state (Scwarzentruber et.al. (1989)’s modification of the Redlich-Kwong EOS) with the Huron-Vidal mixing rule. Three ionic terms were added to this equation – a short-range ionic term, a long-range ionic term (MSA) and a Born term. The thermodynamic model has the advantage that it reduces to a standard cubic equation of state if no ions are present in the solution, and that public available interaction parameters used in the Huron-Vidal mixing rule could be utilized. The originality of this electrolyte equation of state is the use of the Huron-Vidal mixing rule and the addition of a Born term. Compared to electrolyte models based on equations for the gibbs excess energy, the electrolyte equation of state has the advantage that the extrapolation to higher pressures and solubility calculations of supercritical components is less cumbersome. The electrolyte equation of state was able to correlate and predict equilibrium properties of CO₂-MDEA-water solutions with a good precision. It was also able to correlate high pressure data of systems of methane-CO₂-MDEA and water.

The second thermodynamic model (electrolyte CPA-EOS) evaluated in this work is a model where the molecular interactions are modelled with the CPA (cubic plus association) equation of state (Kontogeorgios et.al., 1999) with a classical one-parameter Van der Walls mixing rule. This model has the advantage that few binary interaction parameters have to be used (even for non-ideal solutions), and that its extrapolation capability to higher pressures is expected to be good. In the CPA model the same ionic terms are used as in the electrolyte ScRK-EOS.

A general non-equilibrium two-fluid model was implemented in the simulation program developed in this work. The heat- and mass-transfer calculations were done using an advanced multicomponent mass transfer model based on non-equilibrium thermodynamics. The mass transfer model is flexible and able to simulate many types of non-equilibrium processes we find in the petroleum industry. A model for reactive mass transfer using enhancement factors was implemented for the calculation of mass transfer of CO₂ into amine solutions. The mass transfer model was fitted to the available mass transfer data found in the open literature.

The simulation program was used to analyse and perform parameter fitting to the high pressure experimental data obtained during this work. The mathematical models used in NeqSim were capable of representing the experimental data of this work with a good precision. From the experimental and modelling work done, we could conclude that the mass transfer model regressed to pure low-pressure data also was able to represent the high-pressure mass transfer data with an acceptable precision. Thus the extrapolation capability of the model to high pressures was good.

For a given partial pressure of CO₂ in the natural gas, calculations show a decreased CO₂ capturing capacity of aqueous MDEA solutions at increased natural gas system pressure. A reduction up to 40% (at 200 bar) compared to low pressure capacity is estimated. The pressure effects can be modelled correctly by using suitable thermodynamic models for the liquid and gas. In a practical situation, the partial pressure of CO₂ in the natural gas will be proportional to the total pressure. In these situations, it is shown that the CO₂ capturing capacity of the MDEA solution will be increased at rising total pressures up to 200 bar. However, the increased capacity is not as large as we would expect from the higher CO₂ partial pressure in the gas.

The reaction kinetics of CO₂ with MDEA is shown to be relatively unaffected by the total pressure when nitrogen is used as inert gas. It is however important that the effects of thermodynamic and kinetic non- ideality in the gas and liquid phase are modelled in a consistent way. Using the simulation program NeqSim – some selected high-pressure non-equilibrium processes (e.g. absorption, pipe flow) have been studied. It is demonstrated that the model is capable of simulating equilibrium- and non-equilibrium processes important to the process- and petroleum industry.

Thesis (M.S.)--West Virginia University, 2006.
Title from document title page. Document formatted into pages; contains vii, 88 p. : ill. (some col.), map (part col.). Includes abstract. Includes bibliographical references (p. 47-49).

In late 1992 coalbed methane became the most significant source of natural gas produced in Virginia. This gas is held within the coal formations adsorbed to the coal matrix. The current well stimulation technology applies a high pressure fluid to the coal formation surrounding the wellbore to induce a series of fractures. The research documented in this thesis investigates several new technologies that could replace or augment the current well stimulation approach of hydraulic fracturing. The application of liquid carbon dioxide, as the stimulation agent was investigated in a series of permeability tests. These measurements were made using a radial flow technique developed specifically for this research project. The results of the tests using liquid carbon dioxide to enhance the permeability of coal samples, to methane gas, indicated a significant increase in permeability of the samples. Comparison to a reference material showed, however, that the increase was of a general nature, not by specific interaction with the coal matrix. Rather, the permeability increase was due to reduced resistance of the borehole skin. Studies of the new, radial flow, permeability measurement approach showed good agreement to a conventional, axial flow, approach for similar sample bedding orientation to the gas flow. The documented experiments also include investigations into the potential for using custom designed nitrocellulose/nitroglycerin/RDX based propellant charges to produce extensive fracturing away from the wellbore. The first series of these experiments concerned the characterization of the burn properties for these propellants and their mixtures. Utilizing an interior ballistics approach, these laboratory small-scale shots were numerically modeled with a program written as a part of this project. Using the small-scale results and the modeled data, a series of large-scale test shots were developed and fired to gain understanding of the scale effects. The small-scale constant volume bomb, and the large-scale vented bomb were both custom designed and fabricated for this project. Comparisons of the laboratory data and modeled predictions show good agreement for both the small and large-scale test series. This work concludes by presenting considerations for utilizing the propellant based well stimulation approach in the water filled wells in southwest Virginia.
Ph. D.

Improving methods of hydrocarbon production and developing new techniques for the creation of natural gas storage facilities are critically important for the petroleum industry. This dissertation focuses on two key topics: (1) mechanisms of sand production from petroleum reservoirs and (2) mechanical characterization of caverns created in carbonate rock formations for natural gas storage. Sand production is the migration of solid particles together with the hydrocarbons when extracted from petroleum reservoirs. It usually occurs from wells in sandstone formations that fail in response to stress changes caused by hydrocarbon withdrawal. Sand production is generally undesirable since it causes a variety of problems ranging from significant safety risks during high-rate gas production, to the erosion of downhole equipment and surface facilities. It is widely accepted that a better understanding of the mechanics of poorly-consolidated formations is required to manage sand production; which, in turn, enables the cost effective production of gas and oil resources. In this work, a series of large-scale laboratory experiments was conducted in fully saturated, cohesionless sand layers to model the behavior of a petroleum reservoir near a wellbore. We directly observed several key characteristics of the sand production phenomenon including the formations of a stable cavity around the wellbore and a sub-radial flow channel at the upper surface of the tested layer. The flow channel is a first-order feature that appears to be a major part of the sand production mechanism. The channel cross section is orders of magnitude larger than the particle size, and once formed, the channel becomes the dominant conduit for fluid flow and particle transport. The flow channel developed in all of our experiments, and in all experiments, sand production continued from the developing channel after the cavity around the borehole stabilized. Our laboratory results constitute a well constrained data set that can be used to test and calibrate numerical models employed by the petroleum industry for predicting the sand production phenomenon. Although important for practical applications, real field cases are typically much less constrained. We used scaling considerations to develop a simple analytical model, constrained by our experimental results. We also simulated the behavior of a sand layer around a wellbore using two- and three-dimensional discrete element methods. It appears that the main sand production features observed in the laboratory experiments, can indeed be reproduced by means of discrete element modeling. Numerical results indicate that the cavity surface of repose is a key factor in the sand production mechanism. In particular, the sand particles on this surface are not significantly constrained. This lack of confinement reduces the flow velocity required to remove a particle, by many orders of magnitude. Also, the mechanism of channel development in the upper fraction of the sample can be attributed to subsidence of the formation due to lateral extension when an unconstrained cavity slope appears near the wellbore. This is substantiated by the erosion process and continued production of particles from the flow channel. The notion of the existence of this surface channel has the potential to scale up to natural reservoirs and can give insights into real-world sand production issues. It indicates a mechanism explaining why the production of particles does not cease in many petroleum reservoirs. Although the radial character of the fluid flow eventually stops sand production from the cavity near the wellbore, the production of particles still may continue from the propagating surface (interface) flow channel. The second topic of the thesis addresses factors affecting the geometry and, hence, the mechanical stability of caverns excavated in carbonate rock formations for natural gas storage. Storage facilities are required to store gas when supply exceeds demand during the winter months. In many places (such as New England or the Great Lakes region) where no salt domes are available to create gas storage caverns, it is possible to create cavities in limestone employing the acid injection method. In this method, carbonate rock is dissolved, while CO₂ and calcium chloride brine appear as products of the carbonate dissolution reactions. Driven by the density difference, CO₂ rises towards the ceiling whereas the brine sinks to the bottom of the cavern. A zone of mixed CO₂ , acid, and brine forms near the source of acid injection, whereas the brine sinks to the bottom of the cavern. Characterization of the cavern shape is required to understand stress changes during the cavity excavation, which can destabilize the cavern. It is also important to determine the location of the mixture-brine interface to select the place of acid injection. In this work, we propose to characterize the geometry of the cavern and the location of the mixture-brine interface by generating pressure waves in a pipe extending into the cavern, and measuring the reflected waves at various locations in another adjacent pipe. Conventional governing equations describe fluid transients in pipes loaded only by internal pressure (such as in the water hammer effect). To model the pressure wave propagation for realistic geometries, we derived new governing equations for pressure transients in pipes subjected to changes in both internal and external (confining) pressures. This is important because the internal pressure (used in the measurement) is changing in response to the perturbation of the external pressure when the pipe is contained in the cavern filled with fluids. If the pressure in the cavern is perturbed, the perturbation creates an internal pressure wave in the submerged pipe that has a signature of the cavern geometry. We showed that the classic equations are included in our formulation as a particular case, but they have limited validity for some practically important combinations of the controlling parameters. We linearized the governing equations and formulated appropriate boundary and initial conditions. Using a finite element method, we solved the obtained boundary value problem for a system of pipes and a cavern filled with various characteristic fluids such as aqueous acid, calcium chloride brine, and supercritical CO₂ . We found that the pressure waves of moderate amplitudes would create measurable pressure pulses in the submerged pipe. Furthermore, we determined the wavelengths required for resolving the cavern diameter from the pressure history. Our results suggest that the pressure transients technique can indeed be used for characterizing the geometry of gas storage caverns and locations of fluid interfaces in the acid injection method.

AN ABSTRACT OF THE DISSERTATION OFSUMAN SAURABH, for the Doctor of Philosophy degree in Engineering Science, presented on August 30, 2019, at Southern Illinois University Carbondale.TITLE: GEOMECHANICAL STATE OF ROCKS WITH DEPLETION IN UNCONVENTIONAL COALBED METHANE RESERVOIRSMAJOR PROFESSOR: Dr. Satya HarpalaniOne of the major reservoir types in the class of unconventional reservoirs is coalbed methane. Researchers have treated these reservoirs as isotropic when modeling stress and permeability, that is, mechanical properties in all directions are same. Furthermore, coal is a highly sorptive and stress- sensitive rock. The focus of this dissertation is to characterize the geomechanical aspects of these reservoirs, strain, stresses, effective stress and, using the information, establish the dynamic flow/permeability behavior with continued depletion. Several aspects of the study presented in this dissertation can be easily extended to shale gas reservoirs. The study started with mechanical characterization and measurement of anisotropy using experimental and modeling work, and evaluation of how the sorptive nature of coal can affect the anisotropy. An attempt was also made to characterize the variation in anisotropy with depletion. The results revealed that the coals tested were orthotropic in nature, but could be approximated as transversely isotropic, that is, the mechanical properties were isotropic in the horizontal plane, but significantly different in vertical direction. Mechanical characterization of coal was followed by flow modeling. Stress data was used to characterize the changes in permeability with depletion. This was achieved by plotting stress path followed by coal during depletion. The model developed was used to successfully predict the permeability variation in coal with depletion for elastic deformations. As expected, the developed model failed to predict the permeability variation resulting from inelastic deformation given that it was based on elastic constitutive equations. Hence, the next logical step was to develop a generalized permeability model, which would be valid for both elastic and inelastic deformations. Investigation of the causes of coal failure due to anisotropic stress redistribution during depletion was also carried out as a part of this study. It was found that highly sorptive rocks experience severe loss in horizontal stresses with depletion and, if their mechanical strength is not adequate to support the anisotropic stress redistribution, rock failure can result. In order to develop a generalized permeability model based on stress data, stress paths for three different coal types were established and the corresponding changes in permeability were studied. Stress path plotted in an octahedral mean stress versus octahedral shear stress plane provided a signal for changes in the permeability for both elastic as well as inelastic deformations. This signal was used to develop a mechanistic model for permeability modeling, based on stress redistribution in rocks during depletion. The model was able to successfully predict the permeability variation for all three coal types. Finally, since coal is highly stress- sensitive, changes in effective stresses were found to be the dictating factor for deformations, changes in permeability and possible failure with depletion. Hence, the next step was to develop an effective stress law for sorptive and transversely isotropic rocks. For development of an effective stress law for stress sensitive, transversely isotropic rocks, previously established constitutive equations were used to formulate a new analytical model. The model was then used to study changes in the variation of Biot’s coefficient of these rocks. It was found that Biot’s coefficient, typically less than one, can take values larger than one for these rocks, and their values also change with depletion. The study provides a methodology which can be used to estimate the Biot’s coefficient of any rock. As a final step, preliminary work was carried out on the problem of under-performing coal reservoirs in the San Juan basin, where coal is extremely tight with very low permeability. An extension of the work presented in this dissertation is to use the geomechanical characterization techniques to unlock these reservoirs and improve their performance. The experimental data collected during this preliminary study is included in the last chapter of the dissertation.

Petrophysical evaluation of the Albian age gas bearing sandstone reservoirs of the O-M field, Offshore South Africa has been performed. The main goal of the thesis is to evaluate the reservoir potentials of the field through the integration and comparison of results from core analysis, production data and petrography studies for the evaluation and correction of key petrophysical parameters from wireline logs which could be used to generate an effective reservoir model. A total of ten wells were evaluated and twenty eight sandstone reservoirs were encountered of which twenty four are gas bearing and four are wet within the Albian age depth interval of 2800m to 3500m. Six lithofacies (A1, A2, A3, A4, A5 and A6) were grouped
according to textural and structural features and grain size from the key wells (OP1, OP2 and OP3). Facies A6 was identified as non reservoir rock in terms of reservoir rock quality and facies A1 and A2 were regarded as the best reservoir rock quality. This study identifies the different
rock types that comprise reservoir and non reservoirs. Porosity and permeability are the key parameters for identifying the rock types and reservoir characterization. Pore throat radius was estimated from conventional core porosity and permeability with application of the Winland&rsquo
s method for assessment of reservoir rock quality on the bases of pore throat radius. Results from the Winland&rsquo
s method present five Petrofacies (Mega porous, Macro porous, Meso porous, Micro porous and Nanno porous). The best Petrofacies was mega porous rock type which corresponds to lithofacies A1 and A2. The nano porous rock type corresponds to lithofacies A6 and was subsequently classified as non reservoir rock. The volume of clay model from log was taken from the gamma-ray model corrected by Steiber equations which was based on the level of agreement between log data and the x-ray diffraction (XRD) clay data. The average volume of clay determined ranged from 1 &ndash
28 %. The field average grain density of 2.67 g/cc was determined from core data which is representative of the well formation, hence 2.67 g/cc was used to estimate porosity from the density log. Reservoir rock properties are generally good with reservoir average porosities between 10 &ndash
22 %, an average permeability of approximately 60mD. The laterolog resistivity values have been invasion corrected to yield estimates of the true formation resistivity. In general, resistivities of above 4.0 Ohm-m are productive reservoirs, an average water resistivity of 0.1 Ohm-m was estimated. Log calculated water saturation models were calibrated with capillary pressure and conventional core determined water saturations, and the Simandoux shaly sand model best agree with capillary and conventional core water saturations and was used to determine field water saturations. The reservoir average water saturations range between 23 &ndash
69 %. The study also revealed quartz as being the dominant mineral in addition to abundant chlorite as the major clay mineral. The fine textured and dispersed pore lining chlorite mineral affects the reservoir quality and may be the possible cause of the low resistivity recorded in the area. The reservoirs evaluated in the field are characterized as normally pressured with an average reservoir pressure of 4800 psi and temperature of 220 º
F. An interpreted field aquifer gradient of 0.44 psi/ft (1.01 g/cc) and gas gradient of 0.09 psi/ft (0.2 g/cc) were obtained from repeat formation test measurements. A total of eight gas water contacts were identified in six wells. For an interval to be regarded as having net pay potential, cut-off values were used to distinguish between pay and non-pay intervals. For an interval to be regarded as pay, it must have a porosity value of at least 10 %, volume of clay of less than 40 %, and water saturation of not more than 65 %. A total of twenty four reservoir intervals meet the cut-off criteria and was regarded as net pay intervals. The gross thickness of the reservoirs range from 2.4m to 31.7m and net pay interval from 1.03m to 25.15m respectively. In summary, this study contributes to scale transition issues in a complex gas bearing sandstone reservoirs and serves as a basis for analysis of petrophysical properties in a multi-scale system.

In the recent years, the shale gas discourse has become central to discussions about future energy supply in South Africa. In particular, the Permian black shales of the Lower Ecca Group formations in the Karoo Basin are considered potential source rocks for shale gas. The research presented in this thesis advances the understanding of the shale gas potential of mainly the Prince Albert, Whitehill and Tierberg/Collingham Formations. These shale sequences were sampled from eight deep boreholes spread across the main Karoo Basin and geochemically analysed at the GFZ - Helmholtz Centre Potsdam, Germany. Three key questions guided the study, these are: (i) what is the lithology of the sequence; (ii) where in the basin do the shale sequences attain maximum thickness at optimum depth i.e. beneath 1000-1500m; and (iii) and their shale characteristics. To evaluate these, borehole core logging, petrology and organic geochemistry were used extensively. Petrology involved the use of thin section, scanned electron and transmission electron microscopy for mineralogy as well as the identification of sedimentary features, organic matter and nano-scale porosity. These were coupled with standard organic geochemistry techniques such as Rock Eval. analysis, open pyrolysis gas chromatography and thermovaporisation to quantify the free gas, total organic carbon (TOC), present-day gas generative potential and kerogen type. The results show that the Whitehill Formation, away from the CFB and not intruded by dolerite, has the most potential for shale gas. Microscopic studies of this pyritic black shale reveal the occurrence of porous amorphous matter, indicating thermal maturity within the gas generation zone (i.e. > 1.1 percent Ro, 120ºC). The TOC content is consistently high within the Whitehill (exceeding industry requirement of 2 percent), attaining maximum of 7.3 percent. The highest yields of free and desorbed gas, especially methane, were emitted within this formation (S1 and nC1 peaks); mostly within its dolomitic units. In addition, dissolution porosity within dolomite units of the Whitehill Formation was identified as the predominant type of porosity. Thus, it is deduced that the dolomitic units of Whitehill Formation potentially contain the greatest volumes of free gas. HI values attain maximum of 25 mg HC/g TOC, whereas the OI values 26 mg CO2/g TOC. Such low HI and OI values are typically attributed to the dominance of Type IV kerogen, and consistent with overmaturity. Open pyrolysis (GC) show the main the chemical compound of the organic matter to be m-p-xylene, consistent with a mix of Type III, Type I/II and Type IV kerogen. Lithologically, the Whitehill Formation is composed of ~ 35 quartz, 13 percent feldspar, 26 percent illite and ~ 23 percent dolomite with variable amounts of pyrite. The dominance of quartz is directly proportional to the brittleness of the rock. Thus it can be deduced that the Whitehill Formation is relatively brittle and therefore fraccable. Burial trends indicate increasing depth (from ground level) to the top of the Whitehill Formation towards the south and south-eastern portion of the basin. It is in the southern region where thicknesses of this black shale exceeding 50m occur at depths more than 1500m; 1000m beneath fresh water aquifers. It therefore concluded that Whitehill Formation in the southern portion of Karoo Basin, but away from the thermo-tectonic overprint of the Cape Orogeny, is the most probable shale gas reservoir in South Africa.

Thesis (M.S.)--West Virginia University, 2007.
Title from document title page. Document formatted into pages; contains vii, 102 p. : ill. (some col.), maps (some col.). Includes abstract. Includes bibliographical references (p. 91-94).

This dissertation presents contributions to the understanding of the dynamic nature of permeability of Indonesian coal. It is the first-of-its-kind study, first presenting a comparison of experimental results with those obtained using existing analytical permeability models, and then modifying the existing anisotropic model for application to the unique physical structure of Indonesian coal. The first problem addressed in this dissertation was establishing the pressure-dependentpermeability of coal in a laboratory environment replicating in situ conditions for two coal types from the Sanga Sanga basin of Kalimantan, Indonesia. The change in permeability with depletion and the corresponding volumetric strain of coal were measured in the laboratory under uniaxial strain condition (zero lateral strain). Two gases, helium and methane, were used as the flowing fluids during experimental work. The results showed that, decreasing pore pressure resulted in significant decrease in horizontal stress and increased permeability. The permeability increase at low reservoir pressure was significant, a positive finding for Indonesian coals. Using the measured volumetric changes with variations in pressure, the cleat compressibility for the two coal types was estimated. In a separate effort, volumetric strain as a result of desorption of gases was measured using sister samples under unconstrained condition, in absence of the stress effect. Sorptioninduced strain processes were modeled using the Langmuir-type model to acquire the two important shrinkage parameters. All parameters calculated using the experimental data were used for the modeling exercise. The second component of this dissertation is the permeability variation modeling to enable projecting long-term gas production in the Sanga Sanga basin. For this, two commonly used isotropic permeability models were selected. These models, developed primarily for the San Juan coal, were unable to match the measured permeability data. This was believed to be due to the inappropriate geometry used to represent Indonesian coal, where butt cleats are believed to be absent. This was followed by application of the most recent model, incorporating partial anisotropy in coal. This consideration improved the modeling results although there clearly was room for improvement. The final challenge addressed in this dissertation was to consider the coal geometry appropriate for Indonesian coal, stack of sheets as opposed to a bundle of matchsticks. In order to incorporate the structural anisotropy for the stack of sheets geometry, two input parameters were modified, based on geo-mechanical anisotropy. After applying these to the modified model, the permeability modeling results were compared with the experimental data. The matches improved significantly. Finally, the effect of maximum horizontal stress on permeability of coal was estimated by using high and low maximum horizontal stress values and constant vertical and minimum horizontal stresses. The effect of maximum horizontal stress on permeability was found to be significant under uniaxial strain condition for both coals.

Orientador: Rosângela Barros Zanoni Lopes Moreno
Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica
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Resumo: O comportamento de um reservatório de gás e condensado durante a depleção é altamente complexo. Quando a pressão do reservatório cai abaixo da pressão de orvalho, forma-se um banco de condensado ao redor do poço, que afeta a produtividade do poço e a composição do fluido produzido. Dados experimentais e de campo evidenciam a existência de três regiões no sentido radial, desde a zona imediata ao poço até a zona mais afastada, com variação na saturação de condensado. A primeira região é aquela mais afastada do poço, onde a pressão de reservatório é maior que a pressão de orvalho, e não se tem presença de condensado. A segunda região caracteriza-se pela formação de duas fases no reservatório, embora o condensado ainda não seja móvel nesta região. Na terceira região, a saturação de condensado alcança uma saturação crítica e observa-se o início do escoamento de duas fases. O objetivo deste trabalho é caracterizar as regiões de escoamento no reservatório onde existe formação do banco de condensado e avaliar seu impacto na produtividade do poço. Adicionalmente, busca-se comparar as diferentes técnicas de avaliação deste tipo de reservatório. A análise foi baseada em dados obtidos durante a vida produtiva do poço com uso de ferramentas analíticas e numéricas. As análises dos testes transientes de pressão, em termos de pseudopressão monofásica e bifásica, foram desenvolvidas a partir de dados do período build up de dois testes de pressão utilizando o conhecimento de curvas de permeabilidade relativa. Em seguida, foi construído um modelo numérico de simulação composicional ajustado com os dados existentes dos fluidos e do reservatório, com a finalidade de modelar o comportamento do reservatório de gás condensado. A análise integrada permitiu validar os resultados e prever o comportamento do reservatório no futuro. Como resultados da avaliação foram identificadas as três regiões de escoamento, possibilitando comparar os resultados para permeabilidade, efeito de película e distribuição radial de saturação de condensado utilizando os diferentes métodos de análise. A contribuição deste trabalho reside na integração de análise de testes de poço e simulação numérica neste tipo de reservatório. Além disso, pode-se contribuir para uma melhor gestão do reservatório e procura de soluções para reduzir o efeito de condensação retrógrada
Abstract: The behavior of a gas condensate reservoir during depletion is highly complex. A bank of condensate is formed around the wellbore when the reservoir pressure drops below the dew-point pressure. As a result, the well productivity and the composition of the produced fluid are compromised. Experimental and field data have evidenced the existence of three regions in the radial direction from the zone immediately around to the wellbore to the farthest area, with variations in fluid saturations. In the first region, farthermost from the well, the reservoir pressure is higher than dew point pressure and there is no condensate drop-out. The second region is characterized by the formation of two phases in the reservoir, however the condensate is not mobile. In the third region, the condensate saturation reaches a critical saturation and is observed the beginning of the two-phase flow. This study aims to characterize the condensate bank of the reservoir where gas condensation occurs and to evaluate the condensate bank impact in the well productivity. Additionally, it seeks to compare the different techniques of evaluation of this reservoir type. The analysis was based on pressure data obtained during its productive life, through analytical and numerical tools. The analysis of pressure transient tests, in terms of single phase and two phase pseudo-pressure, were performed on build-up data using the knowledge of relative permeability curves. Further, a numerical compositional model was built and adjusted with the data of the reservoir and its fluids, with the purpose of modeling the behavior of a gas condensate reservoir. The integrated evaluation allowed us to validate the results and predict the behavior of the reservoir in the future. Based on the analysis, three flow regions were identified and it was possible to evaluate the difference on the results for effective permeability, formation damage and radial distribution of condensate saturation using different methods. The contribution of this work lies in integrating well test analysis and numerical simulation to evaluate this type of reservoir. Moreover, results can also contribute for a better reservoir management and as a base for finding solutions to reduce the effect of retrograde condensation
Mestrado
Reservatórios e Gestão
Mestra em Ciências e Engenharia de Petróleo

Hidratos de gás são importantes em questões que vão desde o bloqueio de tubulações na indústria de produção de óleo e gás, até o sequestro de dióxido de carbono, transporte de gás natural, dessalinização de água salgada e purificação de água contaminada. A fim de investigar estes campos e aplicações, necessita-se determinar inicialmente a temperatura e pressão nas quais os hidratos se formam. Isto pode ser feito por meio de experimentos de formação e/ou dissociação de hidratos, bem como utilizando-se de modelos termodinâmicos, correlações empíricas e métodos computacionais. Estudou-se nesse trabalho o desempenho da PC-SAFT na modelagem da fase fluida no equilíbrio da formação de hidratos, comparando seus resultados com a equação de Peng-Robinson e o modelo proposto por Klauda e Sandler. Para a molécula de água, em especial, avaliaram-se as configurações possíveis para o esquema de associação. Para a fase hidrato, avaliou-se a equação de van der Waals e Platteuw (vdWP), e levou-se em conta o efeito das cascas adicionais na estimativa da constante de Langmuir. Por fim, foram propostas duas equações com termos ajustáveis para a fugacidade da água na fase hidrato em função da temperatura, uma linear e outra quadrática, para utilização conjunta com a equação PC-SAFT. Para comparação, quando possível os sistemas foram avaliados com auxílio do software CSMGem. A utilização da equação PC-SAFT em conjunto com as expressões propostas resultou na melhor predição da pressão de equilíbrio em temperaturas determinadas.
Gas hydrates are important for issues that include flow assurance in oil and gas industries, carbon sequestration, natural gas transport, seawater desalinization, and purification of contaminated water. To investigate those fields and applications, temperature and pressure in which hydrates are formed must be determined. This can be done through hydrate formation and/or dissociation experiments, as well as through thermodynamic models, empirical correlations, and computational methods. In this work, the performance of the PC-SAFT in modeling the fluid phase in hydrate phase equilibrium was investigated. Its results were compared to the Peng-Robinson equation of state and to the model proposed by Klauda and Sandler. For the water molecule, different association schemes were considered. For the hydrate phase, the van der Waals and Platteuw (vdWP) equation was used. The effect of additional shells in the estimation of the Langmuir constant was assessed. Finally, equations for water fugacity in hydrate phase, as a function of temperature, were proposed. These equations were intended to be used with the PC-SAFT equation of state, and both linear or quadratic equations were considered. For comparison, when possible the software CSMGem was used to compute the equilibrium conditions. The use of the PC-SAFT EOS, along with the proposed equations, resulted in a better prediction of the equilibrium pressure as a function of temperature.

Les inclusions fluides naturelles peuvent fournir des informations quantitatives précieuses pour reconstruire les conditions de circulation des paléofluides. CO₂, CH₄ et N₂ sont les espèces gazeuses majoritaires le plus souvent rencontrées dans divers environnements géologiques. Cependant les données d’étalonnage des mélanges constitués de ces espèces pour une quantification de leurs propriétés PVX ne sont pas encore complètement établies. L'utilisation des données de calibration disponible dans la littérature peut donc entraîner des erreurs significatives. L'objectif central de ce travail de thèse est d’apporter des données d’étalonnage du signal Raman des gaz CO₂, CH₄, N₂ et de leurs mélanges, sur une gamme de pression de 5 à 600 bars, afin de pouvoir déterminer simultanément les propriétés PVX à une température fixée. Pour cela, des mélanges de gaz ont été préparés à haute pression par le biais d'un mélangeur (GasMix AlyTech) couplé avec un système de pressurisation développé au laboratoire GeoRessources. Des analyses in situ Raman des mélanges de gaz ont été réalisées dans des conditions contrôlées en utilisant le système HPOC couplé avec un microcapillaire transparent placé sur une platine microthermométrique (Linkam CAP500). L’incertitude des mesures des propriétés PVX à 22 ou 32 °C à partir de nos équations d’étalonnage est de < 1 mol%, ~ ± 20 bars et ~ ± 0,02 g.cm-³ pour la composition, la pression et la densité, respectivement. Un autre objectif du projet est d'interpréter la tendance de variation de la position du pic du N₂ et/ou CH₄ pour une compréhension approfondie. Deux modèles théoriques, i.e., le potentiel de Lennard-Jones 6-12 et le modèle « Perturbed hard-sphere fluid » ont été utilisés pour évaluer quantitativement la contribution des forces d'interaction intermoléculaire attractives et répulsives aux décalages des bandes de CH₄ et N₂. Un modèle prédictif a été proposé pour prédire la tendance de la variation de la position du pic du CH₄ jusqu'à 3000 bars en fonction de la pression et de la composition. En fin, l'applicabilité de nos données d'étalonnage aux autres systèmes gazeux ou dans d’autres laboratoires est discutée et évaluée. Des nouvelles données d’étalonnage universelles applicables dans d’autres laboratoires sont fournies. Un programme de calcul « FRAnCIs » avec une interface utilisateur a été développé pour rendre l'utilisation de nos données d'étalonnage accessibles au plus grand nombre
Quantitative knowledge of species trapped within fluid inclusions provides key information to better understand geological processes as well as to reconstruct the conditions of paleofluid circulation. CO₂, CH₄, and N₂ are among the most dominant gas species omnipresent in various geological environments, but their quantitative PVX calibration data are not fully established yet. Using the previously published data can therefore lead to non-quantified errors, especially when applied to geological fluids containing generally several substances at elevated pressure and density. The aim of this work is to provide accurate calibration data for the simultaneous determination of PVX properties of pure gases or any binary and ternary mixtures of CO₂, CH₄, and N₂ over 5 to 600 bars at a fixed temperature, directly from Raman spectra. For this, gas mixtures were prepared and compressed using a mixer (GasMix AlyTech) coupled with a homemade pressurization system. Raman in situ analyses of gas mixtures were performed at controlled conditions using an improved HPOC system (High-Pressure Optical Cell) with a transparent microcapillary containing the prepared gas mixtures, placed on a heating-cooling stage (Linkam CAP500). Overall, the uncertainty of the measurement of the PVX properties of fluid inclusions from our calibration equations at 22 or 32 °C is < ± 1 mol%, ~ ± 20 bars, and ~ ± 0.02 g.cm-³ for molar proportion, pressure and density, respectively. The ensuing aim of the project is to interpret the variation trends of the peak position of the CH₄ and N₂ ν1 band for an in-depth understanding. Two theoretical models, i.e., Lennard-Jones 6-12 potential energy approximation and Perturbed hard-sphere fluid model were involved to quantitatively assess the contribution of the attractive and repulsive intermolecular interaction forces to the pressure-induced frequency shifts. A predictive model was also provided to predict the variation trend of the CH₄ ν1 band over a pressure range up to 3000 bars as a function of pressure and composition. Furthermore, the applicability of our calibration data to other laboratories and apparatus and to gas mixtures that contain a small amount of other species (e.g., H2, H2S) was discussed and evaluated. New universal calibration data applicable for other laboratories were then provided. A computer program “FRAnCIs” was also developed to make the application of our calibration data as convenient as possible via a user-friendly interface

Les prelevements sur l'etna (1978-86) et le momotombo (1985-86) sont effectues a l'aide d'impacteurs en cascade fractionnant l'aerosol en 6 classes granulometriques puis analyses par pixe et sfx. Le comportement en fonction de l'activite volcanique des elements constitutifs et des elements volatiles est etudie. La modelisation thermochimique dynamique realisee permet de conclure sur les mecanismes de generation d'origine haute temperature et la modelisation thermodynamique avec ou sans apport d'air permet de conclure sur les principales voies de condensation du gaz de haute temperature evoluant naturellement

Large volumes of natural gas exist in tight fissured reservoirs. Hydraulic fracturing is one of the main stimulating techniques to enhance recovery from these fractured reservoirs. Although hydraulic fracturing has been used for decades for the stimulation of tight gas reservoirs, a thorough understanding of the interaction between induced hydraulic fractures and natural fractures is still lacking. Recent examples of hydraulic fracture diagnostic data suggest complex, multi-stranded hydraulic fracture geometry is a common occurrence. The interaction between pre-existing natural fractures and the advancing hydraulic fracture is a key condition leading to complex fracture patterns. Large populations of natural fractures that exist in formations such as the Barnett shale are sealed by precipitated cements which could be quartz, calcite, etc. Even though there is no porosity in the sealed fractures, they may still serve as weak paths for fracture initiation and/or for diverting the path of the growing hydraulic fractures. Performing hydraulic fracture design calculations under these complex conditions requires modeling of fracture intersections and tracking fluid fronts in the network of reactivated fissures. In this dissertation, the effect of the cohesiveness of the sealed natural fractures and the intact rock toughness in hydraulic fracturing are studied. Accordingly, the role of the pre-existing fracture geometry is also investigated. The results provide some explanations for significant differences in hydraulic fracturing in naturally fractured reservoirs from non-fractured reservoirs. For the purpose of this research, an extended finite element method (XFEM) code is developed to simulate fracture propagation, initiation and intersection. The motivation behind applying XFEM are the desire to avoid remeshing in each step of the fracture propagation, being able to consider arbitrary varying geometry of natural fractures and the insensitivity of fracture propagation to mesh geometry. New modifications are introduced into XFEM to improve stress intensity factor calculations, including fracture intersection criteria into the model and improving accuracy of the solution in near crack tip regions. The presented coupled fluid flow-fracture mechanics simulations extend available modeling efforts and provide a unified framework for evaluating fracture design parameters and their consequences. Results demonstrate that fracture pattern complexity is strongly controlled by the magnitude of in situ stress anisotropy, the rock toughness, the natural fracture cement strength, and the approach angle of the hydraulic fracture to the natural fracture. Previous studies (mostly based on frictional fault stability analysis) have concentrated on predicting the onset of natural fracture failure. However, the use of fracture mechanics and XFEM makes it possible to evaluate the progression of fracture growth over time as fluid is diverted into the natural fractures. Analysis shows that the growing hydraulic fracture may exert enough tensile and/or shear stresses on cemented natural fractures that they may be opened or slip in advance of hydraulic fracture tip arrival, while under some conditions, natural fractures will be unaffected by the hydraulic fracture. A threshold is defined for the fracture energy of cements where, for cases below this threshold, hydraulic fractures divert into the natural fractures. The value of this threshold is calculated for different fracture set orientations. Finally, detailed pressure profile and aperture distributions at the intersection between fracture segments show the potential for difficulty in proppant transport under complex fracture propagation conditions. Whether a hydraulic fracture crosses or is arrested by a pre-existing natural fracture is controlled by shear strength and potential slippage at the fracture intersections, as well as potential debonding of sealed cracks in the near-tip region of a propagating hydraulic fracture. We introduce a new more general criterion for fracture propagation at the intersections. We present a complex hydraulic fracture pattern propagation model based on the Extended Finite Element Method as a design tool that can be used to optimize treatment parameters under complex propagation conditions.
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Petrophysical evaluation of the Albian age gas bearing sandstone reservoirs of the O-M field, Offshore South Africa has been performed. The main goal of the thesis is to evaluate the reservoir potentials of the field through the integration and comparison of results from core analysis, production data and petrography studies for the evaluation and correction of key petrophysical parameters from wireline logs which could be used to generate an effective reservoir model. A total of ten wells were evaluated and twenty eight sandstone reservoirs were encountered of which twenty four are gas bearing and four are wet within the Albian age depth interval of 2800m to 3500m. Six lithofacies (A1, A2, A3, A4, A5 and A6) were grouped according to textural and structural features and grain size from the key wells (OP1, OP2 and OP3). Facies A6 was identified as non reservoir rock in terms of reservoir rock quality and facies A1 and A2 were regarded as the best reservoir rock quality. This study identifies the different rock types that comprise reservoir and non reservoirs. Porosity and permeability are the key parameters for identifying the rock types and reservoir characterization.

The scale of the energy business today and a favorable and promising economic environment for the production of natural gas, requires study of the thermophysical behavior of fluids: sophisticated experimentation yielding accurate, new volumetric data, and development and improvement of thermodynamic models. This work contains theoretical and experimental contributions in the form of 1) the revision and update of a field model to calculate compressibility factors starting from the gross heating value and the mole fractions of diluents in natural gas mixtures; 2) new reference quality volumetric data, gathered with state of the art techniques such as magnetic suspension densimetry and isochoric phase boundary determinations; 3) a rigorous first-principles uncertainty assessment for density measurements; and 4) a departure technique for the extension of these experimental data for calculating energy functions. These steps provide a complete experimental thermodynamic characterization of fluid samples. A modification of the SGERG model, a standard virial-type model for prediction of compressibility factors of natural gas mixtures, matches predictions from the master GERG-2008 equation of state, using least squares routines coded at NIST. The modification contains new values for parametric constants, such as molecular weights and the universal gas constant, as well as a new set of coefficients. A state-of-the-art high-pressure, single-sinker magnetic suspension densimeter is used to perform density measurements over a wide range of temperatures and pressures. This work contains data on nitrogen, carbon dioxide, and a typical residual gas mixture (95% methane, 4% ethane, and 1% propane). Experimental uncertainty results from a rigorous, first-principles estimation including composition uncertainty effects. Both low- and high-pressure isochoric apparatus are used to perform phase boundary measurements. Isochoric P-T data can determine the phase boundaries. Combined with density measurements, isochoric data provides isochoric densities. Further mathematical treatment, including noxious volume and thermal expansion corrections, and isothermal integration, leads to energy functions and thus to a full thermodynamic characterization.

In this work, a source term model for estimating the rate of spreading and vaporization of LNG on land and sea is introduced. The model takes into account the composition changes of the boiling mixture, the varying thermodynamic properties due to preferential boiling within the mixture and the effect of boiling on conductive heat transfer. The heat, mass and momentum balance equations are derived for continuous and instantaneous spills and mixture thermodynamic effects are incorporated. A parameter sensitivity analysis was conducted to determine the effect of boiling heat transfer regimes, friction, thermal contact/roughness correction parameter and VLE/mixture thermodynamics on the pool spreading behavior. The aim was to provide a better understanding of these governing phenomena and their relative importance throughout the pool lifetime. The spread model was validated against available experimental data for pool spreading on concrete and sea. The model is solved using Matlab for two continuous and instantaneous spill scenarios and is validated against experimental data on cryogenic pool spreading found in literature.