Browsing by Subject "Gas"
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Item Direct estimation of gas reserves using production data(Texas A&M University, 2004-09-30) Buba, Ibrahim MuhammadThis thesis presents the development of a semi-analytical technique that can be used to estimate the gas-in-place for volumetric gas reservoirs. This new methodology utilizes plotting functions, plots, extrapolations, etc. - where all analyses are based on the following governing identity. The 'governing identity' is derived and validated by others for pi less than 6000 psia. We have reproduced the derivation of this result and we provide validation using numberical simulation for cases where pi greater than 6000 psia. The relevance of this work is straightforward using a simple governing relation, we provide a series of plotting functions which can be used to extrapolate or interpret an estimate of gas-in-place using only production data (qg and Gp). The proposed methodology does not require a prior knowledge of formation and or fluid compressibility data, nor does it require average reservoir pressure. In fact, no formation or fluid properties are directly required for this analysis and interpretation approach. The new methodology is validated demonstrated using results from numerical simulation (i.e., cases where we know the exact answer), as well as for a number of field cases. Perhaps the most valuable component of this work is our development of a "spreadsheet" approach in which we perform multiple analyses interpretations simultaneously using MS Excel. This allows us to visualize all data plots simultaneously - and to "link" the analyses to a common set of parameters. While this "simultaneous" analysis approach may seem rudimentary (or even obvious), it provides the critical (and necessary) "visualization" that makes the technique functional. The base relation (given above) renders different behavior for different plotting functions, and we must have a "linkage" that forces all analyses to "connect" to one another. The proposed multiplot spreadsheet approach provides just such a connection.Item Effect of flue gas impurities on the process of injection and storage of carbon dioxide in depleted gas reservoirs(Texas A&M University, 2005-11-01) Nogueira de Mago, Marjorie CarolinaPrevious experiments - injecting pure CO2 into carbonate cores - showed that the process is a win-win technology, sequestrating CO2 while recovering a significant amount of hitherto unrecoverable natural gas that could help defray the cost of CO2 sequestration. In this thesis, I report my findings on the effect of flue gas ??impurities?? on the displacement of natural gas during CO2 sequestration, and results on unconfined compressive strength (UCS) tests to carbonate samples. In displacement experiments, corefloods were conducted at 1,500 psig and 70??C, in which flue gas was injected into an Austin chalk core containing initially methane. Two types of flue gases were injected: dehydrated flue gas with 13.574 mole% CO2 (Gas A), and treated flue gas (N2, O2 and water removed) with 99.433 mole% CO2 (Gas B). The main results of this study are as follows. First, the dispersion coefficient increases with concentration of ??impurities??. Gas A exhibits the largest dispersion coefficients, 0.18-0.25 cm2/min, compared to 0.13-0.15 cm2/min for Gas B, and 0.15 cm2/min for pure CO2. Second, recovery of methane at breakthrough is relatively high, ranging from 86% OGIP for pure CO2, 74-90% OGIP for Gas B, and 79-81% for Gas A. Lastly, injection of Gas A would sequester the least amount of CO2 as it contains about 80 mole% nitrogen. From the view point of sequestration, Gas A would be least desirable while Gas B appears to be the most desirable as separation cost would probably be cheaper than that for pure CO2 with similar gas recovery. For UCS tests, corefloods were conducted at 1,700 psig and 65??C in such a way that the cell throughput of CO2 simulates near-wellbore throughput. This was achieved through increasing the injection rate and time of injection. Corefloods were followed by porosity measurement and UCS tests. Main results are presented as follows. First, the UCS of the rock was reduced by approximately 30% of its original value as a result of the dissolution process. Second, porosity profiles of rock samples increased up to 2.5% after corefloods. UCS test results indicate that CO2 injection will cause weakening of near-wellbore formation rock.Item Effect of pressure-dependent permeability on tight gas wells(Texas A&M University, 2005-08-29) Franquet Barbara, MarielaTight gas reservoirs are those reservoirs where the matrix has a low permeability range (k < 0.1 md). The literature documents laboratory experiments under restressed conditions that show stress dependent rock properties are more significant in tighter rocks. For gas reservoirs, real gas properties are also sensitive to variations of pressure, and the correct description of gas flow must include pressure-dependent gas properties. Under these circumstances the resulting equation for real gas flow is a second order, non-linear, partial differential equation. Non-linearities include pressure-dependence of gas viscosity, gas compressibility, reservoir permeability and reservoir porosity. This paper investigates dynamic permeability change as a function of net overburden stress in tight gas reservoirs. The gas reservoir simulator used for this work included pressure-dependent reservoir permeability. Radial flow cases are analyzed using this simulator. During this study we found that from analysis of production data alone, it is impossible to determine the correct permeability value for tight gas reservoirs with pressure-dependent permeability. For the cases studied, the transient performance was similar for both constant permeability and pressure-dependent permeability. This similarity causes constant permeability and pressure-dependent permeability to be indistinguishable, based on analysis of transient performance data. It was found that the productivity index decreases when pressure-dependent permeability is more significant. Finally, this study verified that the method of Ibrahim et al.28 under estimates original gas in place (OGIP) for tight gas reservoirs with pressure-dependent permeability.Item Essays on Efficiency of the Farm Credit System and Dynamic Correlations in Fossil Fuel Markets(2012-11-28) Dang, Trang Phuong Th 1977-Markets have always changed in response to either exogenous or endogenous shocks. Many large events have occurred in financial and energy markets the last ten years. This dissertation examines market behavior and volatility in agricultural credit and fossil fuel markets under exogenous and endogenous changes in the last ten years. The efficiency of elements within the United States Farm Credit System, a major agricultural lender in the United States, and the dynamic correlation between coal, oil and natural gas prices, the three major fossil fuels, are examined. The Farm Credit system is a key lender in the U.S. agricultural sector, and its performance can influence the performance of the agricultural sector. However, its efficiency in providing credit to the agricultural sector has not been recently examined. The first essay of the dissertation provides assessments on the performance of elements within the Farm Credit System by measuring their relative efficiency using a stochastic frontier model. The second essay addresses the changes in relationship in coal, oil, and natural gas markets with respect to changes and turbulence in the last decade, which has also not been fully addressed in literature. The updated assessment on the relative performance of entities within the Farm Credit System provides information that the Farm Credit Administration and U.S. policy makers can use in their management of and policy toward the Farm Credit System. The measurement of the changes in fossil fuel markets? relationships provides implications for energy investment, energy portfolio anagement, energy risk management, and energy security. It can also be used as a foundation for structuring forecasting models and other models related to energy markets. The dynamic correlations between coal, oil, and natural gas prices are examined using a dynamic conditional correlation multivariate autoregressive conditional heteroskedasticity (MGARCH DCC) model. The estimated results show that the FCS?s five banks and associations with large assets have more efficiently produced credit to the U.S. agricultural sector than smaller sized associations. Management compensation is found to be positively associated with the system?s efficiency. More capital investment and monitoring along with possible consolidation are implied for smaller sized associations to enhance efficiency. On average, the results show that the efficiency of the associations is increasing over time while the average efficiency of the five large banks is more stable. Overall, the associations exhibit a higher variation of efficiency than the five banks. In terms of energy markets the estimates from the MGARCH DCC model indicate significant and changing dynamic correlations and related volatility between the coal, oil, and natural gas prices. The coal price was found to experience more volatility and become more closely related to oil and natural gas prices in recent periods. The natural gas price was found to become more stable and drift away from its historical relationship with oil.Item Evaluation of water production in tight gas sands in the Cotton Valley formation in the Caspiana, Elm Grove and Frierson fields(Texas A&M University, 2007-04-25) Ozobeme, Charles ChineduNormally in tight gas sands, water production is not a problem but in such low permeability reservoirs it is difficult to produce gas at commercial flow rates. Since water is more viscous than gas, very little water is normally produced in low permeability reservoirs. The production of large volumes of water from tight gas sands, say 50-100 bbls of water per MMcf of gas constitutes a cause for concern. High water production (>200 bbls of water per MMcf of gas) has been observed in the low permeability Cotton Valley sands in the Caspiana, Elm Grove and Frierson fields of North Louisiana. This research evaluates water production in the above tight gas sands using field data provided by Matador Resource, a member of the Crisman Institute in Texas A&M university. The research is aimed at providing realistic reservoir scenarios of excess water production in tight gas sands. Log analysis, property trends and well production profiles have been used in establishing the different scenarios. The reservoir simulation results and the production trends show a possible water source from faults and fractures connecting the Travis Peak/Smackover sands to the Cotton Valley sands. An improved understanding of the reservoir would help in further field development.Item Experimental investigation of ultra-fast breakdown at subatmospheric pressures(2007-05) Justis, William Hugo; Krompholz, Hermann G.; Neuber, Andreas A.; Hatfield, Lynn L.Ultra-fast gaseous breakdown is an important area of research in the pulsed power field for applications such as: ultra wideband systems, fast breaking plasma limiters, and ultra fast switches. Using newly developed digitizers and pulsing technology it is possible to accurately investigate breakdown inducing pulses in the sub-nanosecond regime exhibiting rise times on the order of 200 ps with pulse widths under 300 ps. Breakdown is examined in a controlled environment with a pressure range of 10-5 - 600 torr using both argon and dry air as background gases. E/N values range from 103 to 106 Td, and are typically above the threshold for runaway electron generation. Diagnostics include capacitive voltage dividers on incident and transmitted side coaxial lines and X-Ray detection through a scintillator/PMT combination. Initial X-Ray data collected shows the occurrence of high energy runaway electrons during the breakdown event. Breakdown voltages, conduction currents, and formative delay times are also investigated for the full pressure range, with parameters established through both gap and transmission line modeling. Results show consistent breakdown for pressures above 50 torr in a radial gap configuration. A shift of breakdown voltage towards lower pressures for increasing voltage amplitude has been observed. X-ray measurements indicate the presence of fast, high energy electrons across the entire pressure range leading due to runaway electrons. Intensity ratios indicate that electron energies are nearly equivalent to the applied voltage for pressures approaching atmosphere, these results match closely with results obtained from previous testing in axial gap configurations.Item Forecasting of isothermal enhanced oil recovery (EOR) and waterflood processes(2011-12) Mollaei, Alireza; Delshad, Mojdeh; Lake, Larry W.; Patzek, Tadeusz W.; Edgar, Thomas F.; Lasdon, Leon S.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.Item Gas transport properties of reverse selective nanocomposite materials(2007-12) Matteucci, Scott Tyson, 1976-; Freeman, B. D., (Benny D.)The effect of dispersing discreet periclase (magnesium oxide) or brookite (titanium oxide) nanoparticles into poly(1-trimethylsilyl-1-propyne) (i.e., a super glassy polymer) and 1,2-polybutadiene (i.e., a rubbery polymer) has been examined. Particle dispersion has been investigated using atomic force microscopy and transmission electron microscopy to determine particle/aggregate size and distribution. Titanium dioxide nanoparticles dispersed into aggregates on the order of nanometers, as did magnesium oxide in 1,2-polybutadiene. However, the magnesium oxide filled poly(1-trimethylsilyl-1-propyne) did not exhibit nanoparticle aggregates below approximately one micron in characteristic dimensions. Nanocomposite transport properties were studied, where permeability and solubility coefficients were determined for light gases with increasing pressure, and diffusion coefficients were calculated from the solution-diffusion model. The permeability of light gases in the heterogeneous films increased with increasing particle loading. Depending on particle loading, brookite filled nanocomposite light gas permeability increased to over four times that of the unfilled polymer, whereas at high periclase loadings the nanocomposites exhibited light gas permeabilities in excess of an order of magnitude higher than the unfilled materials. Even at these high loadings the light gas selectivities were higher than predicted for films containing transmembrane defects. Solubility was relatively unaffected by the void volume concentration, although it did increase to some extent depending on the nanoparticle concentration. Wide angle X-ray diffraction, nuclear magnetic resonance, and Fourier transform infra-red experiments were used to determine if the nanoparticles remained stable during film preparation. TiO₂ nanoparticles did not appear to react with water, the polymer matrixes or test gases used in this research. However, under certain circumstances, periclase reacted with adventitious water to form brucite. A desilylation reaction occurred when brucite was exposed to polymers or small molecule compounds that contained a trimethylsilyl group attached to a conjugated organic backbone. This reaction caused certain disubstituted polyacetylenes to become insoluble in common organic solvents.Item Identifying and mapping clay-rich intervals in the Fayetteville Shale : influence of clay on natural gas production intervals(2013-12) Roberts, Forrest Daniel; Tinker, Scott W. (Scott Wheeler); Fisher, W. L. (William Lawrence), 1932-The Fayetteville Shale is composed dominantly of clay, carbonate, and siliciclastic minerals. A variety of facies have been described by other workers and in this study, defined by mineral content, biota, fabric, and texture. Because the Fayetteville Shale is one of the top shale-gas producing plays in the U.S., an inquiry into key drivers of good-quality production is worthwhile. In particular, a hypothesis that intervals of high clay content should be avoided as production targets is investigated in this study. A high level of separation between wire-line log neutron porosity (NPHI) and density porosity (DPHI) in the Fayetteville Shale is observed in contrast to the wire-line log responses from the Barnett and Haynesville Shales. Clay minerals have a significant effect on NPHI, which in turn affects separation between NPHI and DPHI (PHISEP). X-Ray Diffraction (XRD) clay data was available for three wells, and efforts to correlate XRD results to PHISEP led to establishing NPHI as a reasonable proxy for clay. Using NPHI as a proxy it was possible to pick clay-rich intervals, map them across the study area, and to determine net clay in the Fayetteville Shale. Maps of net clay-rich intervals were compared to a map of production, but revealed no obvious correlation. Stratigraphic cross-sections showing the clay-rich intervals revealed a clay-poor interval in the upper part of the lower Fayetteville. This interval is the primary target for horizontal well completion. It is bounded above and below by more clay-rich intervals. Establishing the clay-rich intervals via porosity log separation (PHISEP) is one tool to help determine possible stratigraphic zones of gas production and can lead to a better understanding of intervals in which to expect production.Item Massively-Parallel Direct Numerical Simulation of Gas Turbine Endwall Film-Cooling Conjugate Heat Transfer(2011-02-22) Meador, Charles MichaelImprovements to gas turbine efficiency depend closely on cooling technologies, as efficiency increases with turbine inlet temperature. To aid in this process, simulations that consider real engine conditions need to be considered. The first step towards this goal is a benchmark study using direct numerical simulations to consider a single periodic film cooling hole that characterizes the error in adiabatic boundary conditions, a common numerical simpliflication. Two cases are considered: an adiabatic case and a conjugate case. The adiabatic case is for validation to previous work conducted by Pietrzyk and Peet. The conjugate case considers heat transfer in the solid endwall in addition to the fluid, eliminating any simplified boundary conditions. It also includes an impinging jet and plenum, typical of actual endwall configurations. The numerical solver is NEK5000 and the two cases were run at 504 and 128 processors for the adiabatic and conjugate cases respectively. The approximate combined time is 100,000 CPU hours. In the adiabatic case, the results show good agreement for average velocity profiles but over prediction of the film cooling effectiveness. A convergence study suggests that there may be an area of unresolved flow, and the film cooling momentum flux may be too high. Preliminary conjugate results show agreement with velocity profiles, and significant differences in cooling effectiveness. Both cases will need to be refined near the cooling hole exit, and another convergence study done. The results from this study will be used in a larger case that considers an actual turbine vane and film cooling hole arrangement with real engine conditions.Item Systematic study of foam for improving sweep efficiency in chemical enhanced oil recovery(2010-12) Nguyen, Nhut Minh, 1984-; Nguyen, Quoc P.; Pope, Gary A.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.Item Using huff n' puff with a recycled hydrocarbon gas as a means for enhancing oil recovery in a liquid-rich shale reservoir(2016-08) Isbell, Jordan Taylor; Mohanty, Kishore Kumar; Okuno, RyosukeIn recent years, production in unconventional reservoirs has increased exponentially due to technological breakthroughs in horizontal well completions. However, even with new technology, ultimate recovery after primary production in these reservoirs is extremely low (5-10% of original oil in place). The huff n’ puff process is considered to be a strong candidate for enhancing these notoriously-low recovery factors in unconventional reservoirs, especially those that are liquid-rich, in a cost-effective manner. Huff n’ puff is an enhanced oil recovery method in which one well alternates between injection, soaking, and production. Gas injection is often used in this scenario because of its high injectivity compared to water and its ability to develop miscibility with the reservoir oil. In this work, a recycled hydrocarbon gas was used due to its ease of accessibility within the target reservoir. In this work, the application of huff n’ puff to a liquid-rich shale reservoir with nanodarcy-range permeability was investigated both experimentally and numerically. A completely unique experimental setup was fabricated in order to execute oil recovery experiments on preserved core plugs taken from the target reservoir. In these experiments, it was shown that significant amounts of oil could be recovered after two huff n’ puff cycles lasting approximately one day each. Using propane as the injection gas resulted in higher recoveries when compared to the recycled gas due to enhanced miscibility with the oil. It was also shown that the ratio between soaking pressure and production pressure is a significant factor in recovering oil via huff n’ puff. An additional cycle was run with a longer soaking time, but no additional oil was recovered. A set of numerical reservoir models was also created to further investigate the recovery mechanisms in the huff n’ puff process. Lab-scale models were created in an attempt to replicate the experimental findings. The results showed that the recoveries seen in the experiments and simulations were very similar. Also, as long as injection took place above MMP, it was shown that the gas and oil mixed similarly in all cases regardless of pressure. Furthermore, lower production pressures allowed for more gas expansion and therefore better recovery, proving that production pressure alone may be an important parameter rather than the ratio between production and injection pressures. Field-scale models were also created. These models also showed that gas expansion plays a significant role in recovering oil. However, there were several key differences associated with sweep efficiency and the use of live oil versus dead oil.Item Using multi-layer models to forecast gas flow rates in tight gas reservoirs(Texas A&M University, 2007-04-25) Jerez Vera, Sergio ArmandoThe petroleum industry commonly uses single-layer models to characterize and forecast long-term production in tight gas reservoir systems. However, most tight gas reservoirs are layered systems where the permeability and porosity of each layer can vary significantly, often over several orders of magnitude. In addition, the drainage areas of each of the layers can be substantially different. Due to the complexity of such reservoirs, the analysis of pressure and production history using single-layer analyses techniques provide incorrect estimates of permeability, fracture conductivity, drainage area, and fracture half-length. These erroneous values of reservoir properties also provide the reservoir engineer with misleading values of forecasted gas recovery. The main objectives of this research project are: (1) to demonstrate the typical errors that can occur in reservoir properties when single-layer modeling methods are used to history match production data from typical layered tight gas reservoirs, and (2) to use the single-layer match to demonstrate the error that can occur when forecasting long-term gas production for such complex gas reservoirs. A finite-difference reservoir simulator was used to simulate gas production from various layered tight gas reservoirs. These synthetic production data were analyzed using single-layer models to determine reservoir properties. The estimated reservoir properties obtained from the history matches were then used to forecast ten years of cumulative gas production and to find the accuracy of gas reserves estimated for tight gas reservoirs when a single-layer model is used for the analysis. Based on the results obtained in this work, I conclude that the accuracy in reservoir properties and future gas flow rates in layered tight gas reservoirs when analyzed using a single-layer model is a function of the degree of variability in permeability within the layers and the availability of production data to be analyzed. In cases where there is an idea that the reservoir presents a large variability in ????????????k??????, using a multi-layer model to analyze the production data will provide the reservoir engineer with more accurate estimates of long-term production recovery and reservoir properties.