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1
Al-Kharusi, Badr Soud. "Relative permeability of gas-condensate near wellbore, and gas-condensate-water in bulk of reservoir." Thesis, Heriot-Watt University, 2000. http://hdl.handle.net/10399/1098.
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Kgogo, Thabo C. "Well test analysis of low permeability medium-rich to rich gas condensate homogeneous and layered reservoirs." Thesis, Imperial College London, 2011. http://hdl.handle.net/10044/1/6856.
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This study investigates near-wellbore effects during well testing in low permeability, single- and multi-layered, medium-rich to rich, gas condensate reservoirs. Theoretical results obtained from compositional simulations are validated with actual well test data. We first study well test behaviours for a range of gas condensate fluids with increasing condensate to gas ratios (CGR), from lean to medium-rich to rich. We verify that, during a drawdown below the dew point pressure, a condensate bank forms around the wellbore for all fluids studied. We show that, in the case of a medium-rich gas, as pressure increases above the dew point pressure in a subsequent build up, part of the condensate bank closer to the well dissolves into the gas, with the fluid returning to being a single-phase gas. This is different from what happens with rich gas, where the bank disappears completely; and with lean gas, where condensate saturation at the end of a drawdown and in the subsequent build up are very similar. Lean and medium-rich gas condensate fluids yield three-region radial composite derivative behaviours corresponding to dry gas away from the well, condensate bank, and capillary number effects in the immediate vicinity of the well. Only two-region radial composite behaviours are created in the case of rich gas fluids, as rates required to see capillary number effects are not reached in practice. We then study layered systems and show that composite behaviour due to condensate bank and a multi-layer behaviour are superimposed, with the condensate bank appearing on top of multi-layer effects. In addition, the production rate ratio of the most permeable layer rate to the total rate tends to one as the least permeable layer is choked by its condensate bank. We also investigated gravity effects and conclude that gravity has little impact on pressure response once the condensate bank develops near the wellbore and in particular does not create a partial penetration behaviour. Lastly, we show that drilling horizontal wells and hydraulically-fracturing vertical wells improve well productivity when pressure is below the dew point pressure. Condensate drop-out effects are minimized when wells are fractured prior to being produced.
3
Al, Ghamdi Bander Nasser Ayala H. Luis Felipe. "Analysis of capillary pressure and relative permeability effects on the productivity of naturally fractured gas-condensate reservoirs using compositional simulation." [University Park, Pa.] : Pennsylvania State University, 2009. http://etda.libraries.psu.edu/theses/approved/WorldWideIndex/ETD-4622/index.html.
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Ouzzane, Djamel Eddine. "Phase behaviour in gas condensate reservoirs." Thesis, Imperial College London, 2005. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.417922.
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5
Labed, Ismail. "Gas-condensate flow modelling for shale gas reservoirs." Thesis, Robert Gordon University, 2016. http://hdl.handle.net/10059/2144.
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In the last decade, shale reservoirs emerged as one of the fast growing hydrocarbon resources in the world unlocking vast reserves and reshaping the landscape of the oil and gas global market. Gas-condensate reservoirs represent an important part of these resources. The key feature of these reservoirs is the condensate banking which reduces significantly the well deliverability when the condensate forms in the reservoir below the dew point pressure. Although the condensate banking is a well-known problem in conventional reservoirs, the very low permeability of shale matrix and unavailability of proven pressure maintenance techniques make it more challenging in shale reservoirs. The nanoscale range of the pore size in the shale matrix affects the gas flow which deviates from laminar Darcy flow to Knudsen flow resulting in enhanced gas permeability. Furthermore, the phase behaviour of gas-condensate fluids is affected by the high capillary pressure in the matrix causing higher condensate saturation than in bulk conditions. A good understanding and an accurate evaluation of how the condensate builds up in the reservoir and how it affects the gas flow is very important to manage successfully the development of these high-cost hydrocarbon resources. This work investigates the gas Knudsen flow under condensate saturation effect and phase behaviour deviation under capillary pressure of gas-condensate fluids in shale matrix with pore size distribution; and evaluates their effect on well productivity. Supplementary MATLAB codes are provided elsewhere on OpenAIR: http://hdl.handle.net/10059/2145.
6
Vo, Dyung Tien. "Well test analysis for gas condensate reservoirs /." Access abstract and link to full text, 1989. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/9014121.
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Al, Harrasi Mahmood Abdul Wahid Sulaiman. "Fluid flow properties of tight gas-condensate reservoirs." Thesis, University of Leeds, 2011. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.582106.
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Tight gas-condensate reservoirs contain large reserves, but can be extremely costly to develop. Understanding the fundamental controls on the fluid flow behaviour of tight gas and gas-condensate reservoirs has the potential to result in more cost-effective reservoir development and help increase the world's producible reserves. Therefore, the principal objective of the thesis is to improve understanding of multiphase flow within tight gas-condensate reservoirs. In order to achieve this objective a series of pore-to-core scale experiments under controlled conditions were performed, followed by numerical simulation. Three methodologies were used in this study: First, pore-scale experiments in glass micromodels with liquid-liquid systems were performed to improve understanding of the phase separation and flow mechanisms at pore level. Second, coreflood experiments were performed while in-situ saturation was monitored using an X-ray C'I' -scanner. A newly developed liquid-liquid system was used in these experiments. Flow through tight gas sandstones allowed the determination of relative penneabilities as well as determining their dependence on absolute permeability and capillary number. Third, production simulation modelling has been conducted to investigate the implications of the results. The micromodel experiments have proved extremely useful for characterizing the flow behaviour . of condensate systems. The results showed that the flow mechanisms and phases' distributions were affected largely by interfacial tension, pore structure and wettability.
8
Del, Castillo Maravi Yanil. "New inflow performance relationships for gas condensate reservoirs." Texas A&M University, 2003. http://hdl.handle.net/1969/354.
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Aluko, Olalekan A. "Well test dynamics of rich gas condensate reservoirs." Thesis, Imperial College London, 2011. http://hdl.handle.net/10044/1/7887.
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10
Saleh, Amer Mohamed. "Well test and production prediction of gas condensate reservoirs." Thesis, Heriot-Watt University, 1992. http://hdl.handle.net/10399/813.
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11
Daltaban, T. S. "Numerical modelling of recovery processes from gas condensate reservoirs." Thesis, Imperial College London, 1986. http://hdl.handle.net/10044/1/37987.
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12
Rodriguez, Cesar Alexander. "Stress-dependent permeability on tight gas reservoirs." Thesis, Texas A&M University, 2004. http://hdl.handle.net/1969.1/1393.
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People in the oil and gas industry sometimes do not consider pressure-dependent permeability in reservoir performance calculations. It basically happens due to lack of lab data to determine level of dependency. This thesis attempts to evaluate the error introduced in calculations when a constant permeability is assumed in tight gas reservoir. It is desired to determine how accurate are conventional pressure analysis calculations when the reservoir has a strong pressure-dependent permeability. The analysis considers the error due to effects of permeability and skin factor. Also included is the error associated when calculating Original Gas in Place in the reservoir. The mathematical model considers analytical and numerical solutions of radial and linear flow of gas through porous media. The model includes both the conventional method, which assumes a constant permeability (pressure-independent), and a numerical method that incorporates a pressure-dependent permeability. Analysis focuses on different levels of pressure draw down in a well located in the center of a homogeneous reservoir considering two types of flow field geometries: radial and linear. Two different producing control modes for the producer well are considered: constant rate and constant bottom hole pressure. Methodology consists of simulated tight gas well production with k(p) included. Then, we analyze results as though k(p) effects were ignored and finally, observe errors in determining permeability (k) and skin factor (s). Additionally, we calculate pore volume and OGIP in the reservoir. Analysis demonstrates that incorporation of pressure-dependence of permeability k(p) is critical in order to avoid inference of erroneous values of permeability, skin factor and OGIP from well test analysis of tight gas reservoirs. Estimation of these parameters depends on draw down in the reservoir. The great impact of permeability, skin factor and OGIP calculations are useful in business decisions and profitability for the oil company. Miscalculation of permeability and skin factor can lead to wrong decisions regarding well stimulation, which reduces well profitability. In most cases the OGIP calculated is underestimated. Calculated values are lower than the correct value. It can be taken as an advantage if we consider that additional gas wells and reserves would be incorporated in the exploitation plan.
13
Adeyeye, Adedeji Ayoola. "Gas condensate damage in hydraulically fractured wells." Texas A&M University, 2003. http://hdl.handle.net/1969.1/213.
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This project is a research into the effect of gas condensate damage in hydraulically fractured wells. It is the result of a problem encountered in producing a low permeability formation from a well in South Texas owned by the El Paso Production Company. The well was producing a gas condensate reservoir and questions were raised about how much drop in flowing bottomhole pressure below dewpoint would be appropriate. Condensate damage in the hydraulic fracture was expected to be of significant effect.
Previous attempts to answer these questions have been from the perspective of a radial model. Condensate builds up in the reservoir as the reservoir pressure drops below the dewpoint pressure. As a result, the gas moving to the wellbore becomes leaner. With respect to the study by El-Banbi and McCain, the gas production rate may stabilize, or possibly increase, after the period of initial decline. This is controlled primarily by the condensate saturation near the wellbore. This current work has a totally different approach. The effects of reservoir depletion are minimized by introduction of an injector well with fluid composition the same as the original reservoir fluid. It also assumes an infinite conductivity hydraulic fracture and uses a linear model.
During the research, gas condensate simulations were performed using a commercial simulator (CMG). The results of this research are a step forward in helping to improve the management of gas condensate reservoirs by understanding the mechanics of liquid build-up. It also provides methodology for quantifying the condensate damage that impairs linear flow of gas into the hydraulic fracture.
14
Belyadi, Fatemeh. "Determining low permeability formation properties from absolute open flow potential." Morgantown, W. Va. : [West Virginia University Libraries], 2006. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=4879.
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Thesis (M.S.)--West Virginia University, 2006.Title from document title page. Document formatted into pages; contains viii, 63 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 36-42).
15
Almusabeh, Muzher I. "Predicting the gas-condensate extended composition analysis." Morgantown, W. Va. : [West Virginia University Libraries], 2010. http://hdl.handle.net/10450/11076.
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Thesis (M.S.)--West Virginia University, 2010.Title from document title page. Document formatted into pages; contains ix, 52 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 49-51).
16
Carballo, Salas Jose Gilberto. "Alleviation of effective permeability reduction of gas-condensate due to condensate buildup near wellbore." Texas A&M University, 2004. http://hdl.handle.net/1969.1/3245.
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When the reservoir pressure is decreased below dew point pressure of the gas near
the wellbore, gas-condensate wells start to decrease production because condensate is
separated from the gas around the wellbore causing a decrease in gas relative
permeability. This effect is more dramatic if the permeability of the reservoir is low. The
idea proposed for reducing this problem is to eliminate the irreducible water saturation
near the wellbore to leave more space for the gas to flow and therefore increase the
productivity of the well. In this research a simulation study was performed to determine
the range of permeabilities where the cylinder of condensate will seriously affect the
wellÂs productivity, and the distance the removal of water around the wellbore has to be
extended in order to have acceleration of production and an increase in the final reserves.
A compositional-radial reservoir was simulated with one well in the center of 109
grids. Three gas-condensate fluids with different heptanes plus compositions ( 4, 8 and 11
mole %), and two irreducible water saturations were used. The fitting of the Equation of
State (EOS) was performed using the method proposed by Aguilar and McCain. Several
simulations were performed with several permeabilities to determine the permeabilities
for which the productivity is not affected by the presence of the cylinder of condensate.
At constant permeability, various radii of a region of zero initial water saturation
around the wellbore were simulated and comparisons of the effects of removal of
irreducible water on productivity were made.
Reservoirs with permeabilities lower than 100 mD showed a reduction in the
ultimate reserves due to the cylinder of condensate. The optimal radius of water removal
depends on the fluid composition and the irreducible water saturation of the reservoir.
The expected increase in reserves due to water removal varies from 10 to 80 % for gas
production and from 4 to 30% for condensate production.
17
Jamiolahmady, Mahmoud. "Mechanistic modelling of gas-condensate flow in porous media." Thesis, Heriot-Watt University, 2001. http://hdl.handle.net/10399/532.
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Ugwu, Johnson Obunwa. "A semi-empirical approach to modelling well deliverability in gas condensate reservoirs." Thesis, Robert Gordon University, 2011. http://hdl.handle.net/10059/1115.
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A critical issue in the development of gas condensate reservoirs is accurate prediction of well deliverability. In this investigation a procedure has been developed for accurate prediction of well production rates using semi-empirical approach. The use of state of the art fine grid numerical simulation is time consuming and computationally demanding, therefore not suitable for real time rapid production management decisions required on site. Development of accurate fit-for-purpose correlations for fluid property prediction below the saturation pressure was a major consideration to properly allow for retrograde condensation, complications of multiphase flow and mobility issues. Previous works are limited to use of experimentally measured pressure, volume, temperature (PVT) property data, together with static relative permeability correlations for simulation of well deliverability. To overcome the above limitations appropriate fluid property correlations required for prediction of well deliverability and dynamic three phase relative permeability correlation have been developed to enable forecasting of these properties at all the desired reservoir conditions The developed correlations include; condensate hybrid compressibility factor, viscosity, density, compositional pseudo-pressure, and dynamic three phase relative permeability. The study made use of published data bases of experimentally measured gas condensate PVT properties and three phase relative permeability data. The developed correlations have been implemented in both vertical and horizontal well models and parametric studies have been performed to determine the critical parameters that control productivity in gas condensate reservoirs, using specific case studies. The improved correlations showed superior performance over existing correlations on validation. The investigation has built on relevant literature to present an approach that modifies the black oil model for accurate well deliverability prediction for condensate reservoirs at conditions normally ignored by the conventional approach. The original contribution to knowledge and practice includes (i) the improved property correlations equations, (4.44, 4.47, 4.66, 4.69, 4.75, 5.21) and (ii) extension of gas rate equations, for condensate rate prediction in both vertical and horizontal wells. Standard industry software, the Eclipse compositional model, E-300 has been used to validate the procedure. The results show higher well performance compared with the industry standard. The new procedure is able to model well deliverability with limited PVT and rock property data which is not possible with most available methods. It also makes possible evaluation of various enhanced hydrocarbon recovery techniques and optimisation of gas condensate recovery.
19
Mulyadi, Henny. "Determination of residual gas saturation and gas-water relative permeability in water-driven gas reservoirs." Curtin University of Technology, Department of Petroleum Engineering, 2002. http://espace.library.curtin.edu.au:80/R/?func=dbin-jump-full&object_id=12957.
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The research on Determination of Residual Gas Saturation and Gas-Water Relative Permeability in Water-Driven Gas Reservoirs is divided into four stages: literature research, core-flooding experiments, development and application of a new technique for reservoir simulation. Overall, all stages have been completed successfully with several breakthroughs in the areas of Special Core Analysis (SCAL), reservoir engineering and reservoir simulation technology.Initially, a literature research was conducted to survey all available core analysis techniques and their individual characteristics. The survey revealed that there are several core analysis techniques for measuring residual gas saturation (Sgr) and hence, the lack of a commonly agreed method for measuring Sgr. The often-used core analysis techniques are steady-state displacement, co-current imbibition, centrifuge and counter-current imbibition. In this research, all centrifuge tests were performed with a decane-brine system to investigate the possibility of replacing gas with a 'model fluid' to minimise errors due to gas compressibility. Furthermore, Sgr is a function of testing temperature and pressure, types of fluid, wettability, viscosity, flow rate and overburden pressure. Consequently, large uncertainties are associated with measured Sgr and the recoverable gas reserves for water-driven gas reservoirs.Due to the lack of a common method for measuring Sgr, the first important step is to clarify which is the most representative core analysis technique for measuring Sgr. In Stage 2 of the research, core analysis experiments were performed with uniform fluids and ambient temperature. In the core flooding experiments, four different sets of core plugs from various gas reservoirs were selected to cover a wide range of permeability and porosity. Finally, all measured Sgr from the various common core analysis techniques ++were compared.The evidence suggested that steady-state displacement and co-current imbibition tests are the most representative techniques for reservoir application. Steady-state displacement also yields the complete relative permeability (RP) data but it requires long stabilisation times and is costly.In the third stage, a new technique was successfully developed for determining both Sgr and gas-water RP data. The new method consists of an initial co-current imbibition experiment followed by the newly developed correlation (Mulyadi, Amin and Kennaird correlation). Co-current imbibition is used to measure the end-point data, for example, initial water saturation (Swi) and Sgr. The MAK correlation was developed to extend the co-current imbibition test by generating gas-water relative permeability data. Unlike previous correlations, MAK correlation is unique because it incorporates and exhibits the formation properties, reservoir conditions and fluid properties (for example, permeability, porosity, interfacial tension and gas density) to generate the RP curves. The accuracy and applicability of MAK correlations were investigated with several sets of gas-water RP data measured by steady-state displacement tests for various gas reservoirs in Australia, New Zealand, South-East Asia and U.S.A. The MAK correlation proved superior to previously developed correlations to demonstrate its robustness.The purpose of the final stage was to aggressively pursue the possibility of advancing the application of the new technique beyond special core analysis (SCAL). As MAK correlation is successful in describing gas water RP in a core plug scale, it is possible to extend its application to describe the overall reservoir flow behaviour. This investigation was achieved by implementing MAK correlation into a 3-D reservoir simulator (MoReS) and performing simulations on a producing ++
field.The simulation studies were divided into two categories: pre and post upscaled application.The case studies were performed on two X gas-condensate fields: X1 (post upscaled) and X2 (pre upscaled) fields. Since MAK correlation was developed for gas-water systems, several modifications were required to account for the effect of the additional phase (oil) on gas and water RP in gas-condensate systems. In this case, oil RP data was generated by Corey's equations. Five different case studies were performed to investigate the individual and combination effect of implementing MAK correlation, alternative Swi and Sgr correlations and refining porosity and permeability clustering. Moreover, MAK correlation has proven to be effective as an approximation technique for cell by cell simulation to advance reservoir simulation technology.
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Wilson, Benton Wade. "Modeling of performance behavior in gas condensate reservoirs using a variable mobility concept." Texas A&M University, 2003. http://hdl.handle.net/1969.1/317.
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The proposed work provides a concept for predicting well performance behavior in a gas condensate reservoir using an empirical model for gas mobility. The proposed model predicts the behavior of the gas permeability (or mobility) function in the reservoir as condensate evolves and the gas permeability is reduced in the near-well region due to the "condensate bank". The proposed model is based on observations of simulated reservoir performance and predicts the behavior of the gas permeability over time and radial distance. This model is given by:
The proposed concept has potential applications in the development of a pressure-time-radius solution for gas condensate reservoirs experiencing this type of mobility behavior. We recognize that the proposed concept (i.e., a radially-varying gas permeability) is oversimplified, in particular, it ignores the diffusive effects of the condensate (i.e., the viscosity-compressibility behavior). However, we have effectively validated the proposed model using literature results derived from numerical simulation.
This new solution is presented graphically in the form of "type curves." We propose that the "time" form of this solution be used for applications in well test analysis. Previous developments used for the analysis of well test data from gas condensate reservoirs consider the radial composite reservoir model, which utilizes a "step change" in permeability at some radial distance away from the wellbore. Using our proposed solution we can visualize the effect of the varying gas permeability in time and radius (a suite of (dimensionless) radius and time format plots are provided). In short, we can visualize the evolution of the condensate zone as it evolves in time and radial distance.
A limitation is the simplified form of the kg profile as a function of radius and time - as well as the dependence/appropriateness of the α-parameter. While we suspect that the α-parameter represents the influence of both fluid and rock properties, we do not examine how such properties can be used to calculate the α-parameter.
21
Calisgan, Huseyin. "Comprehensive Modelling Of Gas Condensate Relative Permeability And Its Influence On Field Performance." Phd thesis, METU, 2005. http://etd.lib.metu.edu.tr/upload/12606667/index.pdf.
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The productivity of most gas condensate wells is reduced significantly due to condensate banking when the bottom hole pressure falls below the dew point. The liquid drop-out in these very high rate gas wells may lead to low recovery problems. The most important parameter for determining condensate well productivity is the effective gas permeability in the near wellbore region, where very high velocities can occur. An understanding of the characteristics of the high-velocity gas-condensate flow and relative permeability data is necessary for accurate forecast of well productivity.
In order to tackle this goal, a series of two-phase drainage relative permeability measurements on a moderate permeability North Marmara &ndash1 gas well carbonate core plug sample, using a simple synthetic binary retrograde condensate fluid sample were conducted under reservoir conditions which corresponded to near miscible conditions. As a fluid system, the model of methanol/n-hexane system was used as a binary model that exhibits a critical point at ambient conditions. The interfacial tension by means of temperature and the flow rate were varied in the laboratory measurements. The laboratory experiments were repeated for the same conditions of interfacial tension and flow rate at immobile water saturation to observe the influence of brine saturation in gas condensate systems. The laboratory experiment results show a clear trend from the immiscible relative permeability to miscible relative permeability lines with decreasing interfacial tension and increasing velocity. So that, if the interfacial tension is high and the flow velocity is low, the relative permeability functions clearly curved, whereas the relative permeability curves straighten as a linear at lower values of the interfacial tension and higher values of the flow velocity. The presence of the immobile brine saturation in the porous medium shows the same shape of behavior for relative permeability curves with a small difference that is the initial wetting phase saturations in the relative permeability curve shifts to the left in the presence of immobile water saturation. A simple new mathematical model is developed to compute the gas and condensate relative permeabilities as a function of the three-parameter. It is called as condensate number
NK so that the new model is more sensitivity to temperature that represents implicitly the effect of interfacial tension. The new model generated the results were in good agreement with the literature data and the laboratory test results. Additionally, the end point relative permeability data and residual saturations satisfactorily correlate with literature data. The proposed model has fairly good fitness results for the condensate relative permeability curves compared to that of gas case. This model, with typical parameters for gas condensates, can be used to describe the relative permeability behavior and to run a compositional simulation study of a single well to better understand the productivity of the field.
22
Farah, Nicolas. "Flow Modelling in Low Permeability Unconventional Reservoirs." Thesis, Paris 6, 2016. http://www.theses.fr/2016PA066503/document.
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Les réservoirs non-conventionnels présentent un milieu fracturé à multi-échelles, y compris des fractures stimulées et des fractures naturelles, augmentant l'hétérogénéité et la complexité de la simulation de réservoir. Ce travail propose un modèle unique et simple tout en tenant compte des paramètres clés d'un réservoir, tels que l'orientation des fractures, l'anisotropie et la faible perméabilité du réservoir. L'échange matrice-fracture n'est pas correctement modélisé en utilisation les modèles Discrete Fracture Model (DFM) standards en raison de la très faible perméabilité. Dans ce travail nous proposons l'extension de la méthode MINC (Multiple interagissant Continua) aux modèles DFM afin d'améliorer l'échange matrice-fracture. Notre DFM basé sur la méthode MINC, est un modèle triple porosité où les fractures de très grandes conductivités sont explicitement discrétisées et le reste est homogénéisé. Autrement aux modèles standards et afin d'améliorer l'échange de flux entre la matrice et la fracture, une maille matrice est subdivisé selon une fonction de proximité en tenant compte de la distribution des fractures. Notamment, notre approche est particulièrement utile pour les simulations multiphasique avec un changement de phase dans l'échange matrice/fracture, qui ne peut pas être simulé avec une approche standard. Enfin, nous avons appliqué notre approche pour un cas DFN synthétique dans un réservoir de gaz à condensat et un réservoir tight-oil. Un bon accord a été observé en comparant nos résultats à des solutions de référence obtenues avec des maillages très finsUnconventional low permeability reservoirs present a multi-scale fractured media, including stimulated fractures and natural fractures of various sizes, increasing the heterogeneity and the complexity of the reservoir simulation. This work proposes a methodology to address this challenge, taking into account reservoir key parameters such as fractures locations, orientation, anisotropy and low permeability matrix in a unique model as simple as possible. Using standard Discrete Fracture Models (DFMs), the matrix-fracture interaction is not properly handled due to the large grid cells and very low matrix permeability. In this work, we extended the MINC (Multiple INteracting Continua) method to the DFM in order to improve the matrix-fracture flow exchange. Our DFM based on a MINC proximity function is computed by taking into account all discrete fractures, within a triple-porosity model where the propped fractures are explicitly discretized and other fractures are homogenized. In order to improve the flow exchange between the matrix and fracture media, the matrix grid cell is subdivided according to the MINC proximity function based on the distance to all discrete fractures, by using randomly sampled points. Our approach is particularly useful for multi-phase flow simulations in matrix-fracture interaction with phase change, which cannot be handled by a standard approach. Finally, we applied our technique to synthetic DFM case in a retrograde gas and a tight-oil reservoirs. A good agreement is observed by comparing our results to a reference solution where very fine grid cells were used
23
Lakshminarayanan, Sunil. "The impact of relative permeability on type curves for coalbed methane reservoirs." Morgantown, W. Va. : [West Virginia University Libraries], 2006. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=4780.
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Thesis (M.S.)--West Virginia University, 2006.Title from document title page. Document formatted into pages; contains vii, 44 p. : ill. (some col.), maps (part col.). Includes abstract. Includes bibliographical references (p. 43-44).
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Ganti, Gopal. "The effects of permeability and well completion on methane gas production from hydrate bearing reservoir." Morgantown, W. Va. : [West Virginia University Libraries], 2007. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=5138.
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Thesis (M.S.)--West Virginia University, 2007.Title from document title page. Document formatted into pages; contains ix, 67 p. : ill. (some col.), col. map. Includes abstract. Includes bibliographical references (p. 64-67).
25
Ataei, Abdolrahim. "Generalisation of near wellbore relative permeability correlation and modelling of gas condensate flow in perforated region." Thesis, Heriot-Watt University, 2004. http://hdl.handle.net/10399/209.
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Izgec, Bulent. "Performance analysis of compositional and modified black-oil models for rich gas condensate reservoirs with vertical and horizontal wells." Thesis, Texas A&M University, 2003. http://hdl.handle.net/1969.1/237.
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It has been known that volatile oil and gas condensate reservoirs cannot be modeled accurately with conventional black-oil models. One variation to the black-oil approach is the modified black-oil (MBO) model that allows the use of a simple, and less expensive computational algorithm than a fully compositional model that can result in significant timesaving in full field studies. The MBO model was tested against the fully compositional model and performances of both models were compared using various production and injection scenarios for a rich gas condensate reservoir. The software used to perform the compositional and MBO runs were Eclipse 300 and Eclipse 100 versions 2002A. The effects of black-oil PVT table generation methods, uniform composition and compositional gradient with depth, initialization methods, location of the completions, production and injection rates, kv/kh ratios on the performance of the MBO model were investigated. Vertical wells and horizontal wells with different drain hole lengths were used. Contrary to the common belief that oil-gas ratio versus depth initialization gives better representation of original fluids in place, initializations with saturation pressure versus depth gave closer original fluids in place considering the true initial fluids in place are given by the fully compositional model initialized with compositional gradient. Compared to the compositional model, results showed that initially there was a discrepancy in saturation pressures with depth in the MBO model whether it was initialized with solution gas-oil ratio (GOR) and oil-gas ratio (OGR) or dew point pressure versus depth tables. In the MBO model this discrepancy resulted in earlier condensation and lower oil production rates than compositional model at the beginning of the simulation. Unrealistic vaporization in the MBO model was encountered in both natural depletion and cycling cases. Oil saturation profiles illustrated the differences in condensate saturation distribution for the near wellbore area and the entire reservoir even though the production performance of the models was in good agreement. The MBO model representation of compositional phenomena for a gas condensate reservoir proved to be successful in the following cases: full pressure maintenance, reduced vertical communication, vertical well with upper completions, and producer set as a horizontal well.
27
Zhang, Kaiyi. "CO2 Minimum Miscibility Pressure and Recovery Mechanisms in Heterogeneous Low Permeability Reservoirs." Thesis, Virginia Tech, 2019. http://hdl.handle.net/10919/93728.
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Benefited from the efficiency of hydraulic fracturing and horizon drilling, the production of unconventional oil and gas resources, such as shale gas and tight oil, has grown quickly in 21th century and contributed to the North America oil and gas production. Although the new enhancing oil recover (EOR) technologies and strong demand spike the production of unconventional resources, there are still unknowns in recovery mechanisms and phase behavior in tight rock reservoirs. In such environment, the phase behavior is altered by high capillary pressure owing to the nanoscale pore throats of shale rocks and it may also influence minimum miscibility pressure (MMP), which is an important parameter controlling gas floods for CO2 injection EOR. To investigate this influence, flash calculation is modified with considering capillary pressure and this work implements three different method to calculate MMP: method of characteristics (MOC); multiple mixing cell (MMC); and slim-tube simulation. The results show that CO2 minimum miscibility pressure in nanopore size reservoirs are affected by gas-oil capillary pressure owing to the alternation of key tie lines in displacement. The values of CO2-MMP from three different methods match well.
Moreover, in tight rock reservoirs, the heterogeneous pore size distribution, such as the ones seen in fractured reservoirs, may affect the recovery mechanisms and MMP. This work also investigates the effect of pore size heterogeneity on multicomponent multiphase hydrocarbon fluid composition distribution and its subsequent influence on mass transfer through shale nanopores. According to the simulation results, compositional gradient forms in heterogeneous nanopores of tight reservoirs because oil and gas phase compositions depend on the pore size. Considering that permeability is small in tight rocks and shales, we expect that mass transfer within heterogeneous pore size porous media to be diffusion-dominated. Our results imply that there can be a selective matrix-fracture component mass transfer during both primary production and gas injection secondary recovery in fractured shale rocks. Therefore, molecular diffusion should not be neglected from mass transfer equations for simulations of gas injection EOR or primary recovery of heterogeneous shale reservoirs with pore size distribution.Master of Science
The new technologies to recover unconventional resources in oil and gas industry, such as fracturing and horizontal drilling, boosted the production of shale gas and tight oil in 21st century and contributed to the North America oil and gas production. Although the new technologies and strong demand spiked the production of tight oil resources, there are still unknowns of oil and gas flow mechanisms in tight rock reservoirs. As we know, the oil and gas resources are stored in the pores of reservoir formation rock. During production process, the oil and gas are pushed into production wells by formation pressure. However, the pore radius of shale rock is extremely small (around nanometers), which reduces the flow rate of oil and gas and raises capillary pressure in pores. The high capillary pressure will alter the oil and gas phase behavior and it may influence the value of minimum miscibility pressure (MMP), which is an important design parameter for CO2 injection (an important technology to raise production). To investigate this influence, we changed classical model with considering capillary pressure and this modified model is implemented in different methods to calculate MMP. The results show that CO2 -MMP in shale reservoirs are affected by capillary pressure and the results from different methods match well. Moreover, in tight rock reservoirs, the heterogeneous pore size distribution, such as fractures in reservoirs, may affect the flow of oil and gas and MMP value. So, this work also investigates the effect of pore size heterogeneity on oil and gas flow mechanisms. According to the simulation results, compositional gradient forms in heterogeneous nanopores of tight reservoirs and this gradient will cause diffusion which will dominate the other fluid flow mechanisms. Therefore, we always need to consider molecular diffusion in the simulation model for shale reservoirs.
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Saurabh, Suman. "GEOMECHANICAL STATE OF ROCKS WITH DEPLETION IN UNCONVENTIONAL COALBED METHANE RESERVOIRS." OpenSIUC, 2020. https://opensiuc.lib.siu.edu/dissertations/1826.
Full textAbstract:
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.
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Hatami, Mohammad. "Multiscale Analysis of Mechanical and Transport Properties in Shale Gas Reservoirs." Ohio University / OhioLINK, 2021. http://rave.ohiolink.edu/etdc/view?acc_num=ohiou1614950615095796.
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Khaddour, Fadi. "Amélioration de la production de gaz des « Tight Gas Reservoirs »." Thesis, Pau, 2014. http://www.theses.fr/2014PAUU3005/document.
Full textAbstract:
La valorisation des réservoirs gaziers compacts, dits Tight Gas Reservoirs (TGR), dont les découvertes sont importantes, permettrait d’augmenter significativement les ressources mondiales d’hydrocarbures. Dans l’objectif d’améliorer la production de ces types de réservoirs, nous avons mené une étude ayant pour but de parvenir à une meilleure compréhension de la relation entre l’endommagement et les propriétés de transport des géomatériaux. L’évolution de la microstructure d’éprouvettes qui ont été soumises préalablement à des chargements dynamiques est étudiée. Une estimation de leurs perméabilités avec l’endommagement est tout d’abord présentée à l’aide d’un modèle de pores parallèles couplant un écoulement de Poiseuille avec la diffusion de Knudsen. Nous avons ensuite mené des travaux expérimentaux afin d’estimer l’évolution de la perméabilité avec l’endommagement en relation avec l’évolution de la distribution de tailles de pores. Les mesures de perméabilité sont effectuées sur des cylindres en mortier similaire aux roches tight gas, soumis à une compression uniaxiale. La caractérisation des microstructures des mortiers endommagés est réalisée par porosimétrie par intrusion de mercure. Afin d’estimer l’évolution de la perméabilité, un nouveau modèle hiérarchique aléatoire est présenté. Les comparaisons avec les données expérimentales montrent la capacité de ce modèle à estimer non seulement les perméabilités apparentes et intrinsèques mais aussi leurs évolutions sous l’effet d’un chargement introduisant une évolution de la distribution de taille de pores. Ce modèle, ainsi que le dispositif expérimental employé, ont été étendus afin d’estimer à l’avenir les perméabilités relatives de mélanges gazeux. Le dernier chapitre présente une étude de l’adsorption de méthane dans différents milieux fracturés par chocs électriques. Les résultats, utiles pour l’estimation des ressources en place, ont montré que la fracturation permet de favoriser l’extraction du gaz initialement adsorbéThe valorization of compact gas reservoirs, called tight gas reservoirs (TGR), whose discoveries are important, would significantly increase the global hydrocarbon resources. With the aim of improving the production of these types of gas, we have conducted a study to achieve a better understanding of the relationship between damage and the transport properties of geomaterials. The microstructure evolution of specimens, which were submitted beforehand to dynamic loading, has been investigated. An estimation of their permeability upon damage is first presented with the help of a bundle model of parallel capillaries coupling Poiseuille flow with Knudsen diffusion. Then, we have carried out an experimental work to estimate the permeability evolution upon damage in relation to the evolution of the pore size distribution in uniaxial compression. The measurements of permeability have been performed on mortar cylinders, designed to mimic typical tight rocks that can be found in tight gas reservoirs. Microstructural characterization of damaged mortars has been performed with the help of mercury intrusion porosimetry (MIP). To estimate the permeability evolution, a new random hierarchical model has been devised. The comparisons with the experimental data show the ability of this model to estimate not only the apparent and intrinsic permeabilities but also their evolutions under loading due to a change in the pore size distribution. This model and the experimental set up have been extended to estimate the relative permeabilities of gas mixtures in the future. The final chapter presents a study of the adsorption of methane on different porous media fractured by electrical shocks. The results, concerning the estimation of the in-place resources, have shown that fracturing can enhance the extraction of the initial amount of adsorbed gas
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Chanda, Sudipta. "PRELIMINARY EXPERIMENTAL AND MODELING STUDY OF PRESSURE DEPENDENT PERMEABILITY FOR INDONESIAN COALBED METHANE RESERVOIRS." OpenSIUC, 2015. https://opensiuc.lib.siu.edu/dissertations/1224.
Full textAbstract:
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.
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Wang, Yilin. "Simulation of fracture fluid cleanup and its effect on long-term recovery in tight gas reservoirs." [College Station, Tex. : Texas A&M University, 2008. http://hdl.handle.net/1969.1/ETD-TAMU-3222.
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Tschirhart, Nicholas Ray. "The evaluation of waterfrac technology in low-permeability gas sands in the East Texas basin." Texas A&M University, 2005. http://hdl.handle.net/1969.1/2617.
Full textAbstract:
The petroleum engineering literature clearly shows that large proppant volumes
and concentrations are required to effectively stimulate low-permeability gas
sands. To pump large proppant concentrations, one must use a viscous fluid.
However, many operators believe that low-viscosity, low-proppant concentration
fracture stimulation treatments known as ??waterfracs?? produce comparable
stimulation results in low-permeability gas sands and are preferred because they
are less expensive than gelled fracture treatments.
This study evaluates fracture stimulation technology in tight gas sands by using
case histories found in the petroleum engineering literature and by using a
comparison of the performance of wells stimulated with different treatment sizes
in the Cotton Valley sands of the East Texas basin. This study shows that large
proppant volumes and viscous fluids are necessary to optimally stimulate tight
gas sand reservoirs. When large proppant volumes and viscous fluids are not
successful in stimulating tight sands, it is typically because the fracture fluids
have not been optimal for the reservoir conditions. This study shows that
waterfracs do produce comparable results to conventional large treatments in the Cotton Valley sands of the East Texas basin, but we believe it is because the
conventional treatments have not been optimized. This is most likely because
the fluids used in conventional treatments are not appropriate or have not been
used appropriately for Cotton Valley conditions.
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Amante, Joseph David. "Scanning Methods as Monitoring, Verification, and Accounting tools for CO₂ Sequestration in Unconventional Gas Reservoirs." Thesis, Virginia Tech, 2015. http://hdl.handle.net/10919/76047.
Full textAbstract:
Unconventional gas reservoirs in carbon dioxide sequestration activities is a relatively new and unexplored concept currently undergoing pilot scale testing. Sequestration has the potential for enhancing gas recovery while mitigating carbon dioxide to long term storage structures. Due to the extremely complex systems associated with these unconventional reservoirs, modeling becomes difficult to predict accurately. This thesis presents methods to increase the confidence of inferred parameter testing for unconventional reservoir sequestration in both seam coal bed methane wells and a shale wells. Various tests include the use of computed tomography coupled with Avizo modeling software, inductively coupled mass spectrometer fluid transport analysis, pressure transient build tests, liquid level detection, and desorption analysis coupled with cleat image analysis. Analyses of coals performed by both environmental scanning electron microscope (ESEM) and micro CT demonstrate that distributions of cleat porosity in coals are anisotropic and not correlated to the seam depth or location. ESEM is used with micro CT scanning to verify the results before and after the impregnation of the carbonic acid. The micro CT data in Avizo Fire© was used calculate an increase in cleat permeability by 25%. The increase of major flow pathways is caused by the dissolution of carbonates. Changes in the structures were observed qualitatively through ESEM and micro CT and quantitatively through Avizo and inductively coupled mass spectrometry. The results of comparative study between the cleat structures and the desorption of various seams indicate a trend in the cleat porosity and the desorption rate of the coals as well as the cleat porosity and the total gas in various seams.Master of Science
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Kumar, Viren. "Chemical stimulation of gas condensate reservoirs: an experimental and simulation study." Thesis, 2006. http://hdl.handle.net/2152/2559.
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Gilani, Syed Furqan Hassan 1984. "Correlating wettability alteration with changes in gas permeability in gas condensate reservoirs." Thesis, 2010. http://hdl.handle.net/2152/ETD-UT-2010-12-2634.
Full textAbstract:
Altering the wettability of reservoir rock using fluoro-chemical treatments has proved to be a viable solution to the condensate blocking problem in gas wells. Alteration of rock wettability to neutral-wet is the primary reason for improvement in gas and condensate relative permeabilities. Stability/compatibility test, drop tests and X-ray photoelectron spectroscopy (XPS) analysis along with core flood results were used to characterize wettability changes.
XPS tests, drop tests, and relative permeability measurements were conducted and correlated with each other. It is shown that XPS analysis and imbibition tests provide a quantitative measure of chemical adsorption and surface modification, but only a qualitative measure of the possible change in relative permeability. As such these simple analytical tools may be used as a screening tool. A positive but imperfect empirical correlation was obtained with results from core flood experiments. The varying concentration of fluorine observed on the rock surface was found to be directly correlated to the wettability change in the rock, which in turn is responsible for improving the deliverability of wells in gas condensate/volatile oil reservoirs.
The method discussed in this thesis can be used to identify chemical treatments to change rock wettability and, therefore, relative permeability. This provides a simple, quick and inexpensive way to screen chemicals as wettability altering agents and relative permeability modifiers which saves time, cost and effort.text
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Hwang, Jongsoo. "Gas injection techniques for condensate recovery and remediation of liquid banking in gas-condensate reservoirs." Thesis, 2011. http://hdl.handle.net/2152/ETD-UT-2011-05-3558.
Full textAbstract:
In gas-condensate reservoirs, gas productivity declines due to the increasing accumulation of liquids in the near wellbore region as the bottom-hole pressure declines below the dew point pressure. This phenomenon occurs even in reservoirs containing lean gas-condensate fluid. Various methods were addressed to remediate the productivity decline, for example, fracturing, gas injection, solvent injection and chemical treatment. Among them, gas injection techniques have been used as options to prevent retrograde condensation by vaporizing condensate and/or by enhancing condensate recovery in gas-condensate reservoirs. It is of utmost importance that the behavior of liquid accumulation near the wellbore should be described properly as that provides a better understanding of the productivity decline due to the originated from impaired relative mobility of gas.
In this research, several gas injection techniques were assessed by using compositional simulators. The feasibility of different methods such as periodic hot gas injection and gas reinjection using horizontal wells were assessed using different reservoir fluid and injection conditions. It is shown that both the temperature and composition of the injection fluids play a key role in the remediation of productivity and condensate recovery. The combined effect of these parameters were investigated and the resulting impact on gas and condensate production was calculated by numerical simulations in this study. Design parameters pertaining to field development and operations including well configuration and injection/production scheme were also investigated in this study along with the above parameters.
Based on the results, guidelines on design issues relating gas injection parameters were suggested. The various simulation cases with different parameters helped with gaining insight into the strategy of gas injection techniques to remediate the gas productivity and condensate recovery.text
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Fernandez, Martinez Ruth Gabriela. "Altering Wettability in Gas Condensate Sandstone Reservoirs for Gas Mobillity Improvement." Thesis, 2011. http://hdl.handle.net/1969.1/ETD-TAMU-2011-05-9317.
Full textAbstract:
In gas-condensate reservoirs, production rate starts to decrease when retrograde condensation occurs. As the bottomhole pressure drops below the dewpoint, gascondensate and water buildup impede flow of gas to the surface. To stop the impairment of the well, many publications suggest wettability alteration to gas-wetting as a permanent solution to the problem. Previous simulation work suggests an "optimum wetting state" to exist where maximum gas condensate well productivity is reached. This work has direct application in gas-condensate reservoirs, especially in identifying the most effective stimulation treatment which can be designed to provide the optimum wetting conditions in the near-wellbore region. This thesis presents an extensive experimental study on Berea sandstone rocks treated with a fluorinated polymer. Various concentrations of the polymer are investigated to obtain the optimum alteration in wettability to intermediate gas-wet. This wetting condition is achieved with an 8% polymer solution treatment, which yields maximum gas mobility, ultimately increasing the relative permeability curves and allowing enhanced recovery from gas-condensate wells. The treatments are performed mainly at room conditions, and also under high pressure and high temperature, simulating the natural environment of a reservoir. Several experimental techniques are implemented to examine the effect of treatments on wettability. These include flow displacement tests and oil imbibitions. The experimental work took place in the Wettability Research Lab in Texas A&M University at Qatar in Doha, Qatar. The studies in this area are important to improve the productivity of gas-condensate reservoirs where liquid accumulates, decreasing production of the well. Efficiency in the extraction of natural gas is important for the economic and environmental considerations of the oil and gas industry. Wettability alteration is one of the newest stimulation methods proposed by researchers, and shows great potential for future research and field applications.
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Ahmadi, Mohabbat. "Development of a chemical treatment for condensate and water blocking in carbonate gas reservoirs." Thesis, 2010. http://hdl.handle.net/2152/ETD-UT-2010-12-2496.
Full textAbstract:
Many gas wells suffer a loss in productivity due to liquid accumulation in the near wellbore region. This problem starts as the flowing bottom hole pressure drops below the dew point in wells producing from gas condensate reservoirs. Chemical stimulation may be used as a remedy, by altering the wettability to non-liquid wetting. Successful treatments decrease liquid trapping, increase fluids mobility, and improve the well’s deliverability. The main focus in this research was to develop an effective chemical treatment to mitigate liquid blocking in gas wells producing from carbonate reservoirs. In the initial stages, screening tests were developed to quickly and effectively identify suitable chemicals from a large pool of compounds. X-ray Photoelectron Spectroscopy (XPS) measurements, drop imbibition tests, and contact angle measurements with water and n-decane were found to be necessary but not sufficient indicators of the effectiveness of the chemicals and were used as screening tools.
An integral part of the development of the treatment solution was the selection of a solvent mixture capable of delivering the fluorinated chemical to the rock surface. The treatment solution, mixture of chemical dissolved in solvent, must be stable in the presence of both brine and condensate so that it will not precipitate and will not reduce permeability of the rock. Through phase behavior studies the compatibility of the treatment solution and in-situ brines were investigated to reduce the risk of failure in the coreflood experiments. The measured relative permeability values in Texas Cream Limestone and Silurian Dolomite cores are demonstrate from high-pressure, high-temperature coreflood experiments before and after treatment. Measurements were made using a pseudo-steady-state method with synthetic gas-condensate mixtures. To enhance the durability of the treatment a special amine primer is introduced.text
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Al-Anazi, Hamoud Ali. "Experimental measurements of condensate blocking and treatements in low and high permeability cores." Thesis, 2003. http://hdl.handle.net/2152/427.
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Al-Anazi, Hamoud Ali Sharma Mukul M. Pope G. A. "Experimental measurements of condensate blocking and treatements in low and high permeability cores." 2003. http://wwwlib.umi.com/cr/utexas/fullcit?p3117821.
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Bang, Vishal 1980. "Development of a successful chemical treatment of gas wells with condensate or water blocking damage." Thesis, 2007. http://hdl.handle.net/2152/3769.
Full textAbstract:
During production from gas condensate reservoirs, significant productivity loss occurs after the pressure near the production wells drops below the dew point of the hydrocarbon fluid. Several methods such as gas recycling, hydraulic fracturing and solvent injection have been tried to restore gas production rates after a decline in well productivity owing to condensate and/or water blocking. These methods of well stimulation offer only temporary productivity restoration and cannot always be used for a variety of reasons. Significant advances have been made during this study to develop and extend a chemical treatment to reduce the damage caused by liquid (condensate + water) blocking in gas condensate reservoirs. The chemical treatment alters the wettability of water-wet sandstone rocks to neutral wet, and thus reduces the residual liquid saturations and increases gas relative permeability. The treatment also increases the mobility and recovery of condensate from the reservoir. A nonionic polymeric fluoro-surfactant in a glycol-alcohol solvent mixture improved the gas and condensate relative permeabilities by a factor of about 2 on various outcrop and reservoir sandstone rocks. The improvement in relative permeability after chemical treatment was quantified by performing high pressure and high temperature coreflood experiments on outcrop and reservoir cores using synthetic gas mixtures at reservoir conditions. The durability of the chemical treatment has been tested by flowing a large volume of gas-condensate fluids for a long period of time. Solvents used to dissolve and deliver the surfactant play an important part in the treatment, especially in the presence of high water saturation or high salinity brine. A screening test based on phase behavior studies of treatment solutions and brines has been used to select appropriate mixtures of solvents based on reservoir conditions. The adsorption of the surfactant on the rock surface has been measured by measuring the concentration of the surfactant in the effluent. Wettability of treated and untreated reservoir rocks has been analyzed by measuring the USBM and Amott-Harvey wettability indices to evaluate the effect of chemical treatment on wettability. For the first time, chemical treatments have also been shown to remove the damage caused by water blocking in gas wells and for increasing the fracture conductivity and thus productivity of fractured gas-condensate wells. Core flood experiments done on propped fractures show significant improvement in gas and condensate relative permeability due to surface modification of proppants by chemical reatment. Relative permeability measurements have been done on sandstone and limestone cores over a wide range of conditions including high velocities typical of high rate gas wells and corresponding to both high capillary numbers and non-Darcy flow. A new approach has been presented to express relative permeability as a function three non-dimensionless terms; capillary number, modified Reynolds Number and PVT ratio. Numerical simulations using a compositional simulator have been done to better understand and design well treatments as a function of treatment volume and other parameters. Injection of treatment solution and chase gas and the flow back of solvents were simulated. These simulations show that chemical treatments have the potential to greatly increase production with relatively small treatment volumes since only the near-well region blocked by condensate and/or water needs to be treated.
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McCulley, Corey Alan. "Development of a chemical treatment for condensate blocking in tight gas sandstone." Thesis, 2011. http://hdl.handle.net/2152/ETD-UT-2011-05-3601.
Full textAbstract:
Gas wells suffer a decrease in productivity because of the formation of a liquid hydrocarbon “condensate” in the near wellbore area. This "condensate" forms near producing wells when the flowing pressure is below the reservoir fluid's dew point. Several methods have been shown to temporarily alleviate this problem, but eventually the condensate bank reforms and the productivity again decreases. The use of surfactants to alter the near wellbore wettability to neutral wetting is a potential longer term solution to liquid blocking in these reservoirs. This alteration increases the gas and liquid relative permeabilities and thereby the productivity by reducing the residual liquid saturation. This enhancement allows the accumulated liquid to flow and is durable as long as the wettability alteration is persistent.
This solution has been shown to be successful through core flood experiments and field trials in high permeability sandstones, but no improvements had been observed in low permeability cores. As the global demand for energy increases, the petroleum industry has begun to develop unconventional (low permeability) assets, new techniques are needed to maintain and improve their productivity. Liquid blocking in these wells can have a much larger impact on both the gas and condensate production in such low permeability formations. Applying this technique increases both gas and condensate mobility and should increase the economic producing life of these wells.
Core flood experiments were conducted to investigate the ability of a chemical treatment to alter the wettability of low permeability sandstones. Previous experimentation did not find any improvement because the increased capillary forces prevented the treatment solution from being easily displaced. This concealed the benefit achieved when the wettability was altered. These experiments recorded smaller relative permeability increases compared to higher permeability core floods, so super critical carbon dioxide was tested as an alternative solvent. While the new treatment was more injectable, it was not as successful at altering wettability. Progress has been made on a solution to liquid blocking in low permeability sandstones, but additional research needs to be completed to further optimize this method.text
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Morales, Adrian. "A Modified Genetic Algorithm Applied to Horizontal Well Placement Optimization in Gas Condensate Reservoirs." 2010. http://hdl.handle.net/1969.1/ETD-TAMU-2010-12-8873.
Full textAbstract:
Hydrocarbon use has been increasing and will continue to increase for the
foreseeable future in even the most pessimistic energy scenarios. Over the past few
decades, natural gas has become the major player and revenue source for many countries
and multinationals. Its presence and power share will continue to grow in the world
energy mix. Much of the current gas reserves are found in gas condensate reservoirs.
When these reservoirs are allowed to deplete, the pressure drops below the dew point
pressure and a liquid condensate will begin to form in the wellbore or near wellbore
formation, possibly affecting production.
A field optimization includes determining the number of wells, type (vertical,
horizontal, multilateral, etc.), trajectory and location of wells. Optimum well placement
has been studied extensively for oil reservoirs. However, well placement in gas
condensate reservoirs has received little attention when compared to oil. In most cases
involving a homogeneous gas reservoir, the optimum well location could be determined
as the center of the reservoir, but when considering the complexity of a heterogeneous reservoir with initial compositional variation, the well placement dilemma does not
produce such a simple result.
In this research, a horizontal well placement problem is optimized by using a
modified Genetic Algorithm. The algorithm presented has been modified specifically for
gas condensate reservoirs. Unlike oil reservoirs, the cumulative production in gas
reservoirs does not vary significantly (although the variation is not economically
negligible) and there are possibly more local optimums. Therefore the possibility of
finding better production scenarios in subsequent optimization steps is not much higher
than the worse case scenarios, which delays finding the best production plan. The second
modification is developed in order to find optimum well location in a reservoir with
geological uncertainties. In this modification, for the first time, the probability of success
of optimum production is defined by the user.
These modifications magnify the small variations and produce a faster
convergence while also giving the user the option to input the probability of success
when compared to a Standard Genetic Algorithm.
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Chien-HaoShen and 沈建豪. "Analytical and Numerical Studies of CO2 Storage Capacity in Nearly Depleted Gas Condensate Reservoirs." Thesis, 2016. http://ndltd.ncl.edu.tw/handle/12344155680918860124.
Full textAbstract:
博士國立成功大學
資源工程學系
104
The purpose of this study is to develop general analytical equations and type curves for estimating the CO2 storage capacity of natural gas reservoirs. Numerical simulations for different types of natural gas reservoirs were done to study the CO2 storage capacity and to validate the developed analytical solutions. A simulation case study is implemented to calculate the CO2 storage capacity in a target storage site, and the simulated result of CO2 storage capacity is compared by that from the derived p/zmixCO2 plot. This study successfully derives general analytical equations and type curves. This general solution is capable of analytically calculating CO2 storage capacity of dry-gas, wet-gas, and gas-condensate reservoirs. Furthermore, this method is useful for site screening of CO2 storage in depleted natural gas reservoirs. In the gas-production stage, the z-factor of natural gas (z) decreased with the decreasing formation pressure. However, in the CO2-injection stage, the z-factor of mixed gases (zmixCO2) increased when the formation pressure was recovering. Generally, the value of the zmixCO2 was smaller than that of the z-factor of natural gas under a specific formation pressure. If the initial formation pressure (pi) is considered, the value of the pi/zmixCO2 when CO2 injection finished will be higher than that of the pi/zi of the gas-condensate reservoir. More CO2 can be stored in a gas-condensate reservoir than the amount of natural gas produced. Numerical simulations for different types of gas reservoirs were used to study their CO2 storage capacity. Additionally, the comparisons of CO2 storage capacity estimates showed that the outcomes of analytical solutions and numerical simulation were similar. The accuracy of the derived general equation was validated. For the case study, the target site was the Y gas-condensate reservoir located in the Y gas field in northwestern Taiwan. The original gas in place (OGIP) of the Y gas-condensate reservoir was about 45,540 million standard cubic feet (MMSCF) which was estimated from the p/z plot based on the measured productions, formation pressures, and corresponding z-factors. The Y gas-condensate reservoir is a nearly depleted reservoir with a very weak water drive. Geological and numerical models of the Y gas-condensate reservoir were constructed in this study. Before the simulated CO2 injection started, the numerical model was well tuned using history matching. The simulations of CO2 injection showed that the total CO2 injected was 48,870 MMSCF (2.58 million tons) when the formation pressure was recovered to the initial pressure of 4,850 psi. The injection/production ratio (IPR) calculated by the derived equation was 1.44 based on the estimates of the ratio of initial p/z and injected p/zmixCO2 (PZR), dimensionless total equivalent gas ratio (DTE), and dimensionless produced equivalent gas ratio (PEG) of 1.275, 1.088, and 1.028, respectively. The value of IPR from analytical method was identical to that derived using the numerical method.
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Sakhaee-Pour, Ahmad. "Gas flow through shale." 2012. http://hdl.handle.net/2152/22169.
Full textAbstract:
The growing demand for energy provides an incentive to pursue unconventional resources. Among these resources, tight gas and shale gas reservoirs have gained significant momentum because recent advances in technology allowed us to produce them at an economical rate. More importantly, they seem likely to contain a significant volume of hydrocarbon. There are, however, many questions concerning hydrocarbon production from these unconventional resources. For instance, in tight gas sandstone, we observe a significant variability in the producibilities of wells in the same field. The heterogeneity is even present in a single well with changes in depth. It is not clear what controls this heterogeneity. In shale gas, the pore connectivity inside the void space is not well explored and hence, a representative pore model is not available. Further, the effects of an adsorbed layer of gas and gas slippage on shale permeability are poorly understood. These effects play a crucial role in assigning a realistic permeability for shale in-situ from a laboratory measurement. In the laboratory, in contrast to in-situ, the core sample lacks the adsorbed layer because the permeability measurements are typically conducted at small pore pressures. Moreover, the gas slippages in laboratory and in-situ conditions are not identical. The present study seeks to investigate these discrepancies. Drainage and imbibition are sensitive to pore connectivity and unconventional gas transport is strongly affected by the connectivity. Hence, there is a strong interest in modeling mercury intrusion capillary pressure (MICP) test because it provides valuable information regarding the pore connectivity. In tight gas sandstone, the main objective of this research is to find a relationship between the estimated ultimate recovery (EUR) and the petrophysical properties measured by drainage/imbibition tests (mercury intrusion, withdrawal, and porous plate) and by resistivity analyses. As a measure of gas likely to be trapped in the matrix during production---and hence a proxy for EUR---we use the ratio of residual mercury saturation after mercury withdrawal (S[subscript gr]) to initial mercury saturation (S[subscript gi]), which is the saturation at the start of withdrawal. Crucially, a multiscale pore-level model is required to explain mercury intrusion capillary pressure measurements in these rocks. The multiscale model comprises a conventional network model and a tree-like pore structure (an acyclic network) that mimic the intergranular (macroporosity) and intragranular (microporosity) void spaces, respectively. Applying the multiscale model to porous plate data, we classify the pore spaces of rocks into macro-dominant, intermediate, and micro-dominant. These classes have progressively less drainage/imbibition hysteresis, which leads to the prediction that significantly more hydrocarbon is recoverable from microporosity than macroporosity. Available field data (production logs) corroborate the higher producibility of the microporosity. The recovery of hydrocarbon from micro-dominant pore structure is superior despite its inferior initial production (IP). Thus, a reservoir or a region in which the fraction of microporosity varies spatially may show only a weak correlation between IP and EUR. In shale gas, we analyze the pore structure of the matrix using mercury intrusion data to provide a more realistic model of pore connectivity. In the present study, we propose two pore models: dead-end pores and Nooks and Crannies. In the first model, the void space consists of many dead-end pores with circular pore throats. The second model supposes that the void space contains pore throats with large aspect ratios that are connected through the rock. We analyze both the scanning electron microscope (SEM) images of the shale and the effect of confining stress on the pore size distribution obtained from the mercury intrusion test to decide which pore model is representative of the in-situ condition. We conclude that the dead-end pores model is more representative. In addition, we study the effects of adsorbed layers of CH₄ and of gas slippage in pore walls on the flow behavior in individual conduits of simple geometry and in networks of such conduits. The network is based on the SEM image and drainage experiment in shale. To represent the effect of adsorbed gas, the effective size of each throat in the network depends on the pressure. The hydraulic conductance of each throat is determined based on the Knudsen number (Kn) criterion. The results indicate that laboratory measurements made with N₂ at ambient temperature and 5-MPa pressure, which is typical for the transient pulse decay method, overestimate the gas permeability in the early life of production by a factor of 4. This ratio increases if the measurement is run at ambient conditions because the low pressure enhances the slippage and reduces the thickness of the adsorbed layer. Moreover, the permeability increases nonlinearly as the in-situ pressure decreases during production. This effect contributes to mitigating the decline in production rates of shale gas wells. Laboratory data available in the literature for methane permeability at pressures below 7 MPa agree with model predictions of the effect of pressure.text
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Nass, Maria A. "Inflow Performance Relationships (IPR) for Solution Gas Drive Reservoirs -- a Semi-Analytical Approach." 2010. http://hdl.handle.net/1969.1/ETD-TAMU-2010-05-8028.
Full textAbstract:
This work provides a semi-analytical development of the pressure-mobility behavior of solution gas-drive reservoir systems producing below the bubble point pressure. Our primary result is the "characteristic" relation which relates normalized (or dimensionless) pressure and mobility functions. This formulation is proven with an exhaustive numerical simulation study consisting of over 900 different cases. We considered 9 different pressure-volume-temperature (PVT) sets, and 13 different relative permeability cases in the simulation study. We also utilized 7 different depletion scenarios.
The secondary purpose of this work was to develop a correlation of the "characteristic parameter" as a function of rock and fluid properties evaluated at initial reservoir conditions such as: API density, GOR, formation volume factor, viscosity, reservoir pressure, reservoir temperature, oil saturation, relative permeability end points, corey exponents and oil mobility:
We did successfully correlate the characteristic parameter as a function of these variables, which proves that we can uniquely represent the pressure-mobility path during depletion with specific reservoir and fluid property variables, taken as constant values for a particular case.
The functional form of our correlation along with all relevant equations are shown on the body of this document.
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Yan, Bicheng. "A Novel Approach For the Simulation of Multiple Flow Mechanisms and Porosities in Shale Gas Reservoirs." Thesis, 2013. http://hdl.handle.net/1969.1/151163.
Full textAbstract:
The state of the art of modeling fluid flow in shale gas reservoirs is dominated by dual porosity models that divide the reservoirs into matrix blocks that significantly contribute to fluid storage and fracture networks which principally control flow capacity. However, recent extensive microscopic studies reveal that there exist massive micro- and nano- pore systems in shale matrices. Because of this, the actual flow mechanisms in shale reservoirs are considerably more complex than can be simulated by the conventional dual porosity models and Darcy’s Law. Therefore, a model capturing multiple pore scales and flow can provide a better understanding of complex flow mechanisms occurring in these reservoirs.
Through the use of a unique simulator, this research work establishes a micro-scale multiple-porosity model for fluid flow in shale reservoirs by capturing the dynamics occurring in three separate porosity systems: organic matter (mainly kerogen); inorganic matter; and natural fractures. Inorganic and organic portions of shale matrix are treated as sub-blocks with different attributes, such as wettability and pore structures. In the organic matter or kerogen, gas desorption and diffusion are the dominant physics. Since the flow regimes are sensitive to pore size, the effects of smaller pores (mainly nanopores and picopores) and larger pores (mainly micropores and nanopores) in kerogen are incorporated in the simulator. The separate inorganic sub-blocks mainly contribute to the ability to better model dynamic water behavior. The multiple porosity model is built upon a unique tool for simulating general multiple porosity systems in which several porosity systems may be tied to each other through arbitrary transfer functions and connectivities. This new model will allow us to better understand complex flow mechanisms and in turn to extend simulation to the reservoir scale including hydraulic fractures through upscaling techniques
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Murray, Doug, Tetsuya Fujii, and Scott R. Dallimore. "DEVELOPMENTS IN GEOPHYSICAL WELL LOG ACQUISITION AND INTERPRETATION IN GAS HYDRATE SATURATED RESERVOIRS." 2008. http://hdl.handle.net/2429/1424.
Full textAbstract:
There has been a dramatic increase in both the amount and type of geophysical well log data
acquired in gas hydrate saturated rocks. Data has been acquired in both offshore and Arctic
environments; its availability has shed light on the applicability of current tools and the potential
usefulness of recently developed and developing technologies.
Some of the more interesting areas of interest are related to the usefulness of nuclear elemental
spectroscopy data and the comparison of thermal and epithermal neutron porosity measurements,
the measurement of in-situ permeability, the interpretation of electrical borehole image and
borehole sonic data.
A key parameter for reservoir characterization and simulation is formation permeability. A
reasonable understanding of this property is key to the development of future gas hydrate
production.
Typical applications of borehole image data are an appreciation of a reservoir’s geological
environment. In hydrate saturated reservoirs, borehole images can also be used to assist in the
understanding of the gas migratory path to the hydrate bearing formation.
This paper presents a review of some of the current state of the art geophysical log measurements
and their application in hydrate saturated reservoirs..
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Lemiski, Ryan Thomas. "Sedimentology, ichnology, and resource characteristics of the low-permeability Alderson Member, Hatton Gas Pool, southwest Saskatchewan, Canada." Master's thesis, 2010. http://hdl.handle.net/10048/958.
Full textAbstract:
Thesis (M.Sc.)--University of Alberta, 2010.Title from PDF file main screen (viewed on July 2, 2010). A thesis submitted to the Faculty of Graduate Studies and Research in partial fulfillment of the requirements for the degree of Master of Science, Department of Earth and Atmospheric Sciences, University of Alberta. Includes bibliographical references.