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1
Kalantari-Dahaghi, Amirmasoud. "Reservoir modeling of New Albany Shale." Morgantown, W. Va. : [West Virginia University Libraries], 2010. http://hdl.handle.net/10450/11022.
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Thesis (M.S.)--West Virginia University, 2010.Title from document title page. Document formatted into pages; contains xii, 81 p. : ill. (some col.), col. maps. Includes abstract. Includes bibliographical references (p. 68-69).
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Erturk, Mehmet Cihan. "Production Performance Analysis Of Coal Bed Methane, Shale Gas, Andtight Gas Reservoirs With Different Well Trajectories And Completiontechniques." Master's thesis, METU, 2013. http://etd.lib.metu.edu.tr/upload/12615510/index.pdf.
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The large amount of produced oil and gas come from conventional resources all over the world and
these resources are being depleted rapidly. This fact and the increasing oil and gas prices force the
producing countries to find and search for new methods to recover more oil and gas. In order to meet
the demand, the oil and gas industry has been turning towards to unconventional oil and gas reservoirs
which become more popular every passing day. In recent years, they are seriously considered as
supplementary to the conventional resources although these reservoirs cannot be produced at an
economic rate or cannot produce economic volumes of oil and gas without assistance from massive
stimulation treatments, special recovery processes or advanced technologies.
The vast increase in demand for petroleum and gas has encouraged the new technological development
and implementation. A wide range of technologies have been developed and deployed since
1980. With the wellbore technology, it is possible to make use of highly deviated wellbores, extended
reach drilling, horizontal wells, multilateral wells and so on. All of the new technologies and a large
number of new innovations have allowed development of increasingly complex economically
marginal fields where shale gas and coal bed methane are found.
In this study, primary target is to compare different production methods in order to obtain better well
performance and improved production from different types of reservoirs. It is also be given some
technical information regarding the challenges such as hydraulic fracturing and multilateral well
configuration of the unconventional gas reservoir modeling and simulation. With the help of advances
in algorithms, computer power, and integrated software, it is possible to apply and analyze the effect
of the different well trajectories such as vertical, horizontal, and multilateral well on the future
production performance of coal bed methane, shale gas, and tight gas reservoirs. A commercial
simulator will be used to run the simulations and achieve the best-case scenarios. The study will lead
the determination of optimum production methods for three different reservoirs that are explained
above under the various circumstances and the understanding the production characteristic and profile
of unconventional gas systems.
3
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.
4
Knudsen, Brage Rugstad. "Production Optimization in Shale Gas Reservoirs." Thesis, Norwegian University of Science and Technology, Department of Engineering Cybernetics, 2010. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-10035.
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Natural gas from organic rich shales has become an important part of the supply of natural gas in the United States. Modern drilling and stimulation techniques have increased the potential and profitability of shale gas reserves that earlier were regarded as unprofitable resources of natural gas. The most prominent property of shale gas reservoirs is the low permeability. This is also the reason why recovery from shale gas wells is challenging and clarifies the need for stimulation with hydraulic fracturing. Shale gas wells typically exhibit a high initial peak in the production rate with a successive rapid decline followed by low production rates. Liquid accumulation is common in shale wells and is detrimental on the production rates. Shut-ins of shale gas wells is used as a means to prevent liquid loading and boost the production. This strategy is used in a model-based production optimization of one and multiple shale gas well with the objective of maximizing the production and long-term recovery. The optimization problem is formulated using a simultaneous implementation of the reservoir model and the optimization problem, with binary variables to model on/off valves and an imposed minimal production rate to prevent liquid loading. A reformulation of the nonlinear well model is applied to transform the problem from a mixed integer nonlinear program to a mixed integer linear program. Four numerical examples are presented to review the potential of using model-based optimization on shale gas wells. The use of shut-ins with variable duration is observed to result in minimal loss of cumulative production on the long term recovery. For short term production planning, a set of optimal production settings are solved for multiple wells with global constraints on the production rate and on the switching capacity. The reformulation to a mixed integer linear program is shown to be effective on the formulated optimization problems and allows for assessment of the error bounds of the solution.
5
Hartigan, David Anthony. "The petrophysical properties of shale gas reservoirs." Thesis, University of Leicester, 2015. http://hdl.handle.net/2381/32213.
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A significant challenge to the petrophysical evaluation of shale gas systems can be attributed to the conductivity behaviour of clay minerals. This is compounded by centimetre to sub-millimetre vertical and lateral heterogeneity in formation geological and therefore petrophysical properties. Despite this however, we remain reliant on Archie based methods for determining water saturation (Sw), and hence the free gas saturation (1-Sg) in shale gas systems. There is however significant uncertainty in both how resistivity methods are applied and the saturation estimates they produce, due largely as Archie parameter inputs (e.g. a, m, n, and Rw) are difficult to determine in shale gas systems, where obtaining a water sample, or carrying out laboratory experiments on recovered core is often technically impractical. This research assesses the geological implications for, and controls on, variations in pseudo Archie parameters in the Bossier and Haynesville Shale Formations in the northern Gulf of Mexico basin. Investigation has particularly focused on the numerical analysis and systematic modification of Archie parameter values to minimise the error between core SW (Dean Stark analysis) and computed Sw values. Results show that the use of optimised Archie parameters can be effective in predicting SW, particularly in the Haynesville formation, but identifies systematic bias in generated Archie parameters that precludes their accurate physical interpretation. Analysis also suggests that variability in the resistivity (Rt) log response is the principal source of error in Sw estimates in the Bossier Shale. Moreover, results suggest that where clay volume exceeds 28%, the resistivity response becomes increasingly variable and elevated, indicating an apparent clay associated ‘excess resistivity’. This is explained by a geologically consistent model that links increasing clay volume to bulk pore water freshening, supported by empirical adaptations that allow for improved Archie parameter selection and a further reduction in the error of Sw estimates.
6
Serra, Kelsen Valente. "Well testing for solution gas drive reservoirs /." Access abstract and link to full text, 1988. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/8811978.
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Yusuf, Nurudeen. "Modeling well performance in compartmentalized gas reservoirs." [College Station, Tex. : Texas A&M University, 2007. http://hdl.handle.net/1969.1/ETD-TAMU-2107.
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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.
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Yussefabad, Arman G. "A simple and reliable method for gas well deliverability determination." Morgantown, W. Va. : [West Virginia University Libraries], 2007. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=5280.
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Thesis (M.S.)--West Virginia University, 2007.Title from document title page. Document formatted into pages; contains xi, 79 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 42-47).
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Eljack, Hassan Daffalla. "Combine gas deliverability equation for reservoir and well." Morgantown, W. Va. : [West Virginia University Libraries], 2007. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=5285.
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Thesis (M.S.)--West Virginia University, 2007.Title from document title page. Document formatted into pages; contains viii, 56 p. : ill. (some col.). Vita. Includes abstract. Includes bibliographical references (p. 45-46).
11
Ding, Wenzhong. "Analysis of data from a restricted-entry well /." Access abstract and link to full text, 1989. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/9015983.
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Hudson, Michael Robert. "Numerical simulation of hydraulic fracturing in tight gas shale reservoirs." Thesis, University of Leeds, 2017. http://etheses.whiterose.ac.uk/18351/.
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Hydraulic fracturing of tight gas shales is a relatively new method of producing economically from extremely low permeability reservoirs. Due to the low permeability, it is crucial that fracturing treatments are able to efficiently create regions of enhanced permeability in the reservoir. The mechanical properties of prospective shale mean that stress interactions between adjacent fractures can be of real consequence to the efficiency of the treatment, and alternative treatments to mitigate these effects have been designed. The aim of this research is to conduct numerical simulation of alternative treatment designs, and objectively evaluate critical parameters. In particular, key aspects of the socalled Texas Two Step method are simulated. This treatment aims to create zones of altered stress anisotropy between pressurised fractures. This study examines the behaviour of said zones as the distance between the fractures is altered, in parallel with literature describing the method. Explanations for unusual fracture curvature behaviour are provided. Further studies examine fracture reorientation within a modified stress field such as that created by the treatment. Rates of reorientation are measured under varying levels of stress anisotropy, initial fracture length and orientation to the stress field. The influence of pre existing natural fractures on the path of a hydraulic fracture is investigated through further simulations. The effects of natural fracture permeability and interface properties are studied. The impact of shear stress caused by a propagating fracture is also examined, and the possible implications for interpretation of microseismic data discussed. Finally, a new treatment for simultaneous fracturing with reduced stress shadowing is proposed and simulated.
13
Nordsveen, Espen T. "Mixed Integer Model Predictive Control of Multiple Shale Gas Wells." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for teknisk kybernetikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-18400.
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Horizontal wells with multistage hydraulic fracturing are today the most important drilling technology for shale gas extraction. Considered unprofitable before, the production has now become economically profitable due to advances in technology. Shales main characteristics is its low permeability, making the gas challenging and expensive to extract. Hydraulic fracturing stimulates the wells by creating additional conductivity, making the gas flows from storage pores to the well. This flow only possible in a short time scale, and states the need for multistage fracturing. Shale gas flow therefore exhibits a high initial peak, followed by a rapid decline in production rates. The use of shut-ins of shale gas wells allows for pressure build-up and may prevent liquid loading, as a means of boosting production. Shut-ins are used as on/off control variables in short-term model-based optimization of multiple shale gas wells with the objective of tracking a reference rate, while at the same time avoiding liquid loading. Previous work have focused on open-loop optimization. Here, an open-loop formulation is compared to a closed-loop formulation, in the form of mixed integer model predictive control. Both formulations are implemented in IBM ILOG CPLEX, with and without disturbances. Optimal production settings are solved in the presence of global constraints on production rates and minimal shut-in time. This allows for shut-ins with variable periods. The implementation is sensitive to initial conditions, horizons and weighting factors. The closed-loop formulation shows the best ability to reduce the effects of disturbances.
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Hersandi, Sandi Rizman. "Modeling of Water Behavior in Hydraulically-Fractured Shale Gas Wells." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2013. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-23614.
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This study presents the modeling of water behavior in hydraulically-fractured of shale gas wells. A five layers model represents a hydraulically-fractured shale gas well was built in Sensor reservoir simulator through Pipe-It, integrated asset management software. Stress dependent permeability multiplier is applied in the model to represent the permeability enhancement in the zone close to the fracture face during the fracturing stimulation. An implicit black-oil logarithmic model with a total of grid number of 5,800 and thickness of 200 ft is used as the base case model. The horizontal well extends through the reservoir in x-direction. The fracture is located in the center of x-axis, while the tip of the fracture is in the middle of y-axis.Water behavior in the fracture for this study is represented by water saturation within the fracture grids. A better understanding of water behavior in the fracture and its effects on the production profile was obtained through several sensitivity cases, which include number of layers, perforation location, matrix permeability, gas production rate, and shut-in time.Based on the sensitivity tests, it was observed that high water saturation in the fracture is found when the perforation is located in the uppermost layer of the model. For matrix permeability sensitivity, the total kh for the model is maintained at a constant. Reservoir with high matrix permeability in the uppermost layer gives higher water saturation in the fracture. The varying gas production rates influence the water saturation in the fracture. Higher gas rates result in higher water saturation in the fracture. The water saturation profile analysis based on the rate sensitivity shows that a critical gas rate to feed the water from the matrix to the fracture is expected to exist. Water saturation profiles in the matrix have relatively the same profile according to shut-in sensitivity. These differing water saturation profiles on the shut-in sensitivity indicate delayed of water feed from the matrix to the fracture.Also, different perforation locations affect the water production profile, but not on the gas production profiles. Both gas and water production profiles are not significantly affected by different matrix permeability values. Rate sensitivity shows that higher gas rate results in higher total water production. Shut-In period also affects the production profiles. Gas and water productions are observed to decrease with an increased shut-in time due to the delay of production. It is noteworthy that the differences in total water productions are substantial. This is due to shut-in period after water injection reduces water recovery, as compared to immediate production after water injection.From the sensitivities applied to the model, water saturation in the fracture is generally affected by all sensitivity parameters, thus also affects production profiles. This study contributes to having a better understanding in the water behavior in the fracture and the production profiles of shale well gas.
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Hammond, Christopher D. (Christopher Daniel). "Economic analysis of shale gas wells in the United States." Thesis, Massachusetts Institute of Technology, 2013. http://hdl.handle.net/1721.1/83718.
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Thesis (S.B.)--Massachusetts Institute of Technology, Department of Mechanical Engineering, 2013.Cataloged from PDF version of thesis.
Includes bibliographical references (pages 65-66).
Natural gas produced from shale formations has increased dramatically in the past decade and has altered the oil and gas industry greatly. The use of horizontal drilling and hydraulic fracturing has enabled the production of a natural gas resource that was previously unrecoverable. Estimates of the size of the resource indicate that shale gas has the potential to supply decades of domestically produced natural gas. Yet there are challenges surrounding the production of shale gas that have not yet been solved. The economic viability of the shale gas resources has recently come into question. This study uses a discounted cash flow economic model to evaluate the breakeven price of natural gas wells drilled in 7 major U.S. shale formations from 2005 to 2012. The breakeven price is the wellhead gas price that produces a 10% internal rate of return. The results of the economic analysis break down the breakeven gas price by year and shale play, along with P20 and P80 gas prices to illustrate the variability present. Derived vintage supply curves illustrate the volume of natural gas that was produced economically for a range of breakeven prices. Historic Natural Gas Futures Prices are used as a metric to determine the volumes and percentage of total yearly production that was produced at or below the Futures Price of each vintage year. From 2005 to 2008, the total production of shale gas resulted in a net profit for operators. A drop in price in 2009 resulted in a net loss for producers from 2009 to 2012. In 2012, only 26.5% of the total gas volume produced was produced at or below the 2012 Natural Gas Futures Price.
by Christopher D. Hammond.
S.B.
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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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Deshpande, Vaibhav Prakashrao. "General screening criteria for shale gas reservoirs and production data analysis of Barnett shale." [College Station, Tex. : Texas A&M University, 2008. http://hdl.handle.net/1969.1/ETD-TAMU-2357.
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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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Botner, Elizabeth. "Elevated methane levels from biogenic coalbed gas in Ohio drinking water wells near shale gas extraction." University of Cincinnati / OhioLINK, 2015. http://rave.ohiolink.edu/etdc/view?acc_num=ucin1439295392.
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Hatzignatiou, Dimitrios Georgios. "Advances in well testing for solution-gas-drive reservoirs /." Access abstract and link to full text, 1990. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/9033497.
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Fleming, Ruven C. "Shale gas extraction in Europe and Germany : the impacts of environmental protection and energy security on emerging regulations." Thesis, University of Aberdeen, 2015. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=228565.
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Shale gas extraction is a technology that is recently arriving in Europe and Germany. The technology brings about a considerable amount of potential environmental threats, but the extraction of shale gas also promises energy security rewards. When the European and German systems for energy and environmental regulation were developed, shale gas extraction did not exist as a technical possibility. Both systems are, hence, not entirely adapted to this technology. This work highlights different ways in which the European and German legislator could act to close existing gaps in their regulatory systems. This could mainly be done by supplementing the existing system with new, shale gas specific regulations. These regulations should be summarized in a new-build shale gas law. The current work tracks the different stages of development of such a new shale gas law, starting from the level of rather abstract constitutional objectives, which translate into clearer defined environmental principles, which in turn translate into a concrete law. Experience from other European states with the legal handling of shale gas extraction teaches that there are essentially two different orientations for such a new-build shale gas law. One is the adoption of a prohibitive moratorium and the other is the implementation of a cautious, but permissive shale gas law. This work`s original contribution to knowledge is the insight that constitutional pre-settings on the interplay of environmental protection with energy security make a cautious, but permissive shale gas law a measure that is legally sounder than a shale gas moratorium. Legally sound, in this context, means complying, to the greatest extent possible, with the applicable constitutional and quasi-constitutional objectives. A shale gas moratorium only serves one purpose, environmental protection, and does not take sufficient account of the energy security objective. A shale gas moratorium only serves one purpose, environmental protection, and does not take sufficient account of the energy security objective. A cautious, but permissive shale gas law, by contrast, possesses the ability to reconcile the competing interests of environmental protection and energy security, which makes it more resilient to judicial review than a moratorium. Having said that, it must be emphasised that shale gas regulation is ultimately a political decision and the legislator is allowed to pick either of the described solutions. This work merely describes which solution is the legally soundest in the sense defined above. To sum up, results from this study will extent what is currently known about the constitutional pre-conditions for the development of shale gas regulation. It highlight that constitutional objectives have a significant impact on the shape of energy regulation.
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Amin, Aram. "Well test analysis of infrequent flow behaviour of fractured wells in oil and gas reservoirs." Thesis, Imperial College London, 2012. http://hdl.handle.net/10044/1/24556.
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The purpose of hydraulic fracturing is to increase the contact area of the wellbore in the reservoir to maximise production rates. For modelling purposes, the induced fracture is assumed to be of infinite or finite conductivity. The modelled fracture tends to show either features of infinite conductivity with half slope or finite conductivity with quarter slope at early time. These flow behaviours are clear indications of a stimulated well. However, observations in some post-frac well tests report a single unit slope in early time, which indicates non-fractured well response. The objective of this study is to investigate the unusual flow behaviour associated with the testing of fractured wells following a proppant frac job and address reasons for this behaviour assuming the frac job has targeted the reservoir interval of interest. This infrequent behaviour is referred to briefly in a limited number of publications but with no clear explanation. Study suggests that the controlling factors are fracture length, fracture conductivity, non-Darcy flow in the case of gas wells and the damage caused by the fracture operation including choked fracture effect and less importantly fracture face skin. This study utilizes 3-D numerical black oil and compositional simulation in single and multi-layered reservoirs containing different fluid types. A range of factors are examined that may impact the introduced fracture flow behaviour based on actual fractured well flow features found in the literature. The main fracture and reservoir parameters investigated include: fracture half-length (xf), fracture conductivity (kfwf), fracture damage including fracture choke (Sfc) and fracture face skin (Sff), non-Darcy effect, formation permeability and many others. The study also examines fractured well behaviour in naturally fractured reservoirs and gas-condensate (lean and rich) reservoirs to investigate liquid drop out effect on the induced fracture flow behaviour. It is concluded that the investigated fracture behaviour is likely to be associated with damaged fractures of short lengths and low fracture conductivity values, which often result from poorly executed frac job on the well. Knowledge obtained from the study is applied to the analysis of well tests from actual fractured wells. Understanding the flow behaviour of fractured wells is crucial to operators and service companies in evaluating the effectiveness of stimulation work performed on the well.
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Huls, Boyd T. "A feasibility study on modeling and prediction of production behavior in naturally fractured shale reservoirs." Morgantown, W. Va. : [West Virginia University Libraries], 2004. https://etd.wvu.edu/etd/controller.jsp?moduleName=documentdata&jsp%5FetdId=3726.
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Thesis (M.S.)--West Virginia University, 2004.Title from document title page. Document formatted into pages; contains viii, 105 p. : ill. (some col.), map. Includes abstract. Includes bibliographical references (p. 96-97).
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Ahmadi, Mahdi. "Ozone Pollution of Shale Gas Activities in North Texas." Thesis, University of North Texas, 2016. https://digital.library.unt.edu/ark:/67531/metadc849624/.
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The effect of shale gas activities on ground-level ozone pollution in the Dallas-Fort Worth area is studied in detail here. Ozone is a highly reactive species with harmful effects on human and environment. Shale gas development, or fracking, involves activities such as hydraulic fracturing, drilling, fluid mixing, and trucks idling that are sources of nitrogen oxides (NOX) and volatile organic compounds (VOC), two of the most important precursors of ozone. In this study two independent approaches have been applied in evaluating the influences on ozone concentrations. In the first approach, the influence of meteorology were removed from ozone time series through the application of Kolmogorov-Zurbenko low-pass filter, logarithmic transformation, and subsequent multi-linear regression. Ozone measurement data were acquired from Texas Commission on Environmental Quality (TCEQ) monitoring stations for 14 years. The comparison between ozone trends in non-shale gas region and shale gas region shows increasing ozone trends at the monitoring stations in close proximity to the Barnett Shale activities. In the second approach, the CAMx photochemical model was used to assess the sensitivity of ozone to the NOX and VOC sources associated with shale oil and gas activities. Brute force method was applied on Barnett Shale and Haynesville Shale emission sources to generate four hypothetical scenarios. Ozone sensitivity analysis was performed for a future year of 2018 and it was based on the photochemical simulation that TCEQ had developed for demonstrating ozone attainment under the State Implementation Plan (SIP). Results showed various level of ozone impact at different locations within the DFW region attributed to area and point sources of emissions in the shale region. Maximum ozone impact due to shale gas activities is expected to be in the order of several parts per billion, while lower impacts on design values were predicted. The results from the photochemical modeling can be used for health impact assessment and air quality management purposes. Both studies in this research show that the impact of shale gas development on local and regional level of ozone is significant, and therefore, it should be considered in the implementation of effective air quality strategies.
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Hu, Yue. "Total Organic Carbon and Clay Estimation in Shale Reservoirs Using Automatic Machine Learning." Thesis, Virginia Tech, 2021. http://hdl.handle.net/10919/105040.
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High total organic carbon (TOC) and low clay content are two criteria to identify the "sweet spots" in shale gas plays. Recently, machine learning has been proved to be effective to estimate TOC and clay from well loggings. The remaining questions are what algorithm we should choose in the first place and whether we can improve the already built models. Automatic machine learning (AutoML) appears as a promising tool to solve those realistic questions by training multiple models and compares them automatically. Two wells with conventional well loggings and elemental capture spectroscopy are selected from a shale gas play to test the AutoML's ability in TOC and clay estimation. TOC and clay content are extracted from the Schlumberger's ELAN interpretation and calibrated to cores. Generalizability is proved in the blind test well and the mean absolute test errors for TOC and clay estimation are 0.23% and 3.77%. 829 data points are used to generate the final models with the train-test ratio of 75:25. The mean absolute test errors are 0.26% and 2.68% for TOC and clay, respectively, which are very low for TOC ranging from 0-6% and clay from 35-65%. The results show the AutoML's success and efficiency in the estimation. The trained models are interpreted to understand the variables effects in predictions. 235 wells are selected through data quality checking and feed into the models to create TOC and clay distribution maps. The maps provide guidance on where to drill a new well for higher shale gas production.Master of Science
Locating "sweet spots", where the shale gas production is much higher than the average areas, is critical for a shale reservoir's successful commercial exploitation. Among the properties of shale, total organic carbon (TOC) and clay content are often selected to evaluate the gas production potential. For TOC and clay estimation, multiple machine learning models have been tested in recent studies and are proved successful. The questions are what algorithm to choose for a specific task and whether the already built models can be improved. Automatic machine learning (AutoML) has the potential to solve the problems by automatically training multiple models and comparing them to achieve the best performance. In our study, AutoML is tested to estimate TOC and clay using data from two gas wells in a shale gas field. First, one well is treated as blind test well and the other is used as trained well to examine the generalizability. The mean absolute errors for TOC and clay content are 0.23% and 3.77%, indicating reliable generalization. Final models are built using 829 data points which are split into train-test sets with the ratio of 75:25. The mean absolute test errors are 0.26% and 2.68% for TOC and clay, respectively, which are very low for TOC ranging from 0-6% and clay from 35-65%. Moreover, AutoML requires very limited human efforts and liberate researchers or engineers from tedious parameter-tuning process that is the critical part of machine learning. Trained models are interpreted to understand the mechanism behind the models. Distribution maps of TOC and clay are created by selecting 235 gas wells that pass the data quality checking, feeding them into trained models, and interpolating. The maps provide guidance on where to drill a new well for higher shale gas production.
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Evans, Morgan Volker. "Microbial transformations of organic chemicals in produced fluid from hydraulically fractured natural-gas wells." The Ohio State University, 2019. http://rave.ohiolink.edu/etdc/view?acc_num=osu1555609276432456.
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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.
Full textAbstract:
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.
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Wang, Cong. "A Multi-Scale, Multi-Continuum and Multi-Physics Model to Simulate Coupled Fluid Flow and Geomechanics in Shale Gas Reservoirs." Thesis, Colorado School of Mines, 2018. http://pqdtopen.proquest.com/#viewpdf?dispub=10684514.
Full textAbstract:
In this study, several efficient and accurate mathematical models and numerical solutions to unconventional reservoir development problems are developed. The first is the three-dimensional embedded discrete fracture method (3D-EDFM), which is able to simulate fluid flow with multiple 3D hydraulic fractures with arbitrary strike and dip angles, shapes, curvatures, conductivities and connections. The second is a multi-porosity and multi-physics fluid flow model, which can capture gas flow behaviors in shales, which is complicated by highly heterogeneous and hierarchical rock structures (ranging from organic nanopores, inorganic nanopores, less permeable micro-fractures, more permeable macro-fractures to hydraulic fractures). The third is an iterative numerical approach combining the extended finite element method (X-FEM) and the embedded discrete fracture method (EDFM), which is developed for simulating the fluid-driven fracture propagation process in porous media.
Physical explanations and mathematical equations behind these mathematical models and numerical approaches are described in detail. Their advantages over alternative numerical methods are discussed. These numerical methods are incorporated into an in-house program. A series of synthetic but realistic cases are simulated. Simulated results reveal physical understandings qualitatively and match with available analytical solutions quantitatively. These novel mathematical models and computational solutions provide numerical approaches to understand complicated physical phenomena in developing unconventional reservoirs, thus they help in the better management of unconventional reservoirs.
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Dohde, Farhan A. "Estimation of Air Emissions During Production Phase from Active Oil and Gas Wells in the Barnett Shale Basin: 2010-2013." Thesis, University of North Texas, 2015. https://digital.library.unt.edu/ark:/67531/metadc799523/.
Full textAbstract:
The Barnett shale basin, the largest onshore gas field in the state of Texas, mainly produces natural gas. The basin’s oil and gas productions have dramatically increased over the past two decades with the enhancement via shale fracturing (fracking) technology. However, recent studies suggest that air emissions from shale fracking have significantly contributed to the growing air pollution problem in North Texas. In this study, air emissions from the Barnett shale basin during the production phase of the oil and gas activities (once the product is collected from the wells) are quantified. Oil and gas production data were acquired from the Texas Railroad Commission for the baseline years of 2010 through 2013. Methodology from prior studies on shale basins approved by the Texas Commission on Environmental Quality was employed in this study and the emission inventories from the production phase sources were quantified. Accordingly, the counties with the most gas operations in the basin, Tarrant, Johnson, Denton and Wise, were found to be the highest emitters of air pollutants. Tarrant County was responsible for the highest emitted NOx (42,566 tons) and CO (17,698 tons) in the basin, while Montague County released the maximum VOC emissions (87,601 tons) during the study period. Amongst the concerned emitted pollutants, VOC was the largest emitted pollutant during the study period (417,804 tons), followed by NOx (126,691 tons) and CO (47,884 tons). Significant Sources of air emissions include: storage tanks, wellhead compressor engines, and pneumatic devices. Storage tanks and pneumatic devices contributed to about 62% and 28% of the total VOC emissions, respectively. Whereas, wellhead compressor engines are primarily responsible for about 97% of the total NOx emissions. Finally, in Tarrant, Wise and Denton counties, the emissions increased during the study period due to increase in the oil and gas production, while Johnson County’s emission contribution declined throughout the study period.
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Campbell, Stuart Alexander. "The Ecca type section (Permian, South Africa) : an outcrop analogue study of conventional and unconventional hydrocarbon reservoirs." Thesis, Rhodes University, 2015. http://hdl.handle.net/10962/d1018199.
Full textAbstract:
The Karoo Basin of South Africa holds an estimated 906 billion to 11 trillion cubic meters of unconventional shale gas within the shales of the Whitehill and Collingham formations of the Ecca Group. Evaluation of this potential resource has been limited due to the lack of exploration and a scarcity of existing drill core data. In order to circumnavigate this problem this study was undertaken to evaluate the potential target horizons exposed in outcrops along the southern portion of the Karoo Basin, north of Grahamstown in the Eastern Cape Province. Detailed field logging was done on the exposed Whitehill and Collingham formations as well as a possible conventional sandstone (turbidite) reservoir, the Ripon Formation, along road cuttings of the Ecca Pass. Palaeocurrent data, jointing directions and fossil material were also documented. Samples were analysed for mineralogy, porosity, permeability, and total organic carbon content (TOC). The extensively weathered black shales of the Whitehill Formation contain a maximum TOC value of 0.9% and the Collingham Formation shales contain a maximum TOC value of 0.6%. The organic lithic arkose sandstones of the Ripon Formation are classified as ‘tight rock’ with an average porosity of 1% and an average permeability of 0.05 mD. The Whitehill Formation in the southern portion of the Karoo Basin has experienced organic matter loss due to low grade metamorphism as well as burial to extreme depths, thus reducing shale gas potential. The Ripon Formation is an unsuitable conventional reservoir along the southern basin boundary due to extensive cementation and filling of pore spaces.
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Kamgang, Thierry T. "Petro physical evaluation of four wells within Cretaceous gas-bearing sandstone reservoirs, In block 4 and 5 orange basin, South Africa." University of the Western Cape, 2013. http://hdl.handle.net/11394/4259.
Full textAbstract:
Masters of SciencePetrophysical evaluation of four wells within Cretaceous gas-bearing sandstone reservoirs in blocks 4 and 5 Orange Basin, South Africa. Thierry Kamgang The present research work evaluates the petrophysical characteristics of the Cretaceous gasbearing sandstone units within Blocks 4 and 5 offshore South Africa. Data used to carry out this study include: wireline logs (LAS format), base maps, well completion reports, petrography reports, conventional core analysis report and tabulated interpretative age reports from four wells (O-A1, A-N1, P-A1 and P-F1). The zones of interest range between 1410.0m-4100.3m depending on the position of the wells. The research work is carried out in two phases: The first phase corresponds to the interpretation of reservoir lithologies based on wireline logs. This consists of evaluating the type of rocks (clean or tight sandstones) forming the reservoir intervals and their distribution in order to quantify gross zones, by relating the behavior of wireline logs signature based on horizontal routine. Extensively, a vertical routine is used to estimate their distribution by correlating the gamma-ray logs of the corresponding wells, but also to identify their depositional environments (shallow to deep marine).Sedlog software is used to digitize the results. The second phase is conducted with the help of Interactive Petrophysics (version 4) software, and results to the evaluation of eight petrophysical parameters range as follow: effective porosity (4.3% - 25.4%), bulk volume of water (2.7% – 31.8%), irreducible water saturation (0.2%-8.8%), hydrocarbon saturation (9.9% - 43.9%), predicted permeability (0.09mD – 1.60mD), volume of shale (8.4% - 33.6%), porosity (5.5% - 26.2%) and water saturation (56.1% - ii 90.1%). Three predefined petrophysical properties (volume of shale, porosity and water saturation)are used for reservoir characterization. The volume of shale is estimated in all the wells using corrected Steiber method. The porosity is determined from the density logs using the appropriate equations in wells O-A1 and P-A1, while sonic model is applied in well A-N1 and neutron-density relationship in well P-F1. Formation water resistivity (Rw) is determined through the following equation: Rw = (Rmf × Rt) / Rxo, and water saturation is calculated based on Simandoux relation. Furthermore, a predicted permeability function is obtained from the crossplot of core porosity against core permeability, and it results match best with the core permeability of well O-A1. This equation is used to predict the permeability in the other wells. The results obtained reveal that average volumes of shale decrease from the west of the field towards the east; while average porosities and water saturations increase from the south-west through the east despite the decreasing average water saturation in well P-A1. A corroboration of reference physical properties selected for reservoir characterization, with predefined cut-off values result to no net pay zones identified within the reservoir intervals studied. Consequently, it is suggested that further exploration prospects should be done between well O-A1 and A-N1.
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Sakinejad, Michael Cyrus. "The Landscape Legacies of Gas Drilling in North Texas." Thesis, University of North Texas, 2016. https://digital.library.unt.edu/ark:/67531/metadc849745/.
Full textAbstract:
In North Texas, the Barnett Shale underlies large areas of the Dallas-Fort Worth Metroplex (DFW), which magnifies debates about the externalities of shale gas development (SGD). Continued demand for natural gas and expansive urbanization in DFW will cause more people to come in contact with drilling rigs, gas transport, and other urban shale gas landscapes. Thousands of gas wells within the DFW region occupy a large, yet scattered land surface area. DFW city planners, elected officials, and other stakeholders must deal with current and future urban growth and the surface impacts that are associated with gas development. This research examines how shale gas landscapes affect urban land uses, landscapes, and patterns of development in DFW. The study focuses on multiple fast growing DFW municipalities that also have high numbers of gas well pad sites. This study asks what are the spatial characteristics of gas well production sites in DFW and how do these sites vary across the region; how do gas well production sites affect urban growth and development; and how are city governments and surface developers responding to gas well production sites, and what are the dominant themes of contestation arising around gas well production sites and suburban growth?
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Zhang, Kaiyi. "CO2 Minimum Miscibility Pressure and Recovery Mechanisms in Heterogeneous Low Permeability Reservoirs." Thesis, Virginia Tech, 2019. http://hdl.handle.net/10919/93728.
Full textAbstract:
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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Du, Fengshuang. "Investigation of Nanopore Confinement Effects on Convective and Diffusive Multicomponent Multiphase Fluid Transport in Shale using In-House Simulation Models." Diss., Virginia Tech, 2020. http://hdl.handle.net/10919/100103.
Full textAbstract:
Extremely small pore size, low porosity, and ultra-low permeability are among the characteristics of shale rocks. In tight shale reservoirs, the nano-confinement effects that include large gas-oil capillary pressure and critical property shifts could alter the phase behaviors, thereby affecting the oil or gas production. In this research, two in-house simulation models, i.e., a compositionally extended black-oil model and a fully composition model are developed to examine the nano-pore confinement effects on convective and diffusive multicomponent multiphase fluid transport. Meanwhile, the effect of nano-confinement and rock intrinsic properties (porosity and tortuosity factor) on predicting effective diffusion coefficient are investigated.
First, a previously developed compositionally extended black-oil simulation approach is modified, and extended, to include the effect of large gas-oil capillary pressure for modeling first contact miscible (FCM), and immiscible gas injection. The simulation methodology is applied to gas flooding in both high and very low permeability reservoirs. For a high permeability conventional reservoir, simulations use a five-spot pattern with different reservoir pressures to mimic both FCM and immiscible displacements. For a tight oil-rich reservoir, primary depletion and huff-n-puff gas injection are simulated including the effect of large gas-oil capillary pressure in flow and in flash calculation on recovery estimations. A dynamic gas-oil relative permeability correlation that accounts for the compositional changes owing to the produced gas injection is introduced and applied to correct for changes in interfacial tension (IFT), and its effect on oil recovery is examined. The results show that the simple modified black-oil approach can model well both immiscible and miscible floods, as long as the minimum miscibility pressure (MMP) is matched. It provides a fast and robust alternative for large-scale reservoir simulation with the purpose of flaring/venting reduction through reinjecting the produced gas into the reservoir for EOR.
Molecular diffusion plays an important role in oil and gas migration in tight shale formations. However, there are insufficient reference data in the literature to specify the diffusion coefficients within porous media. Another objective of this research is to estimate the diffusion coefficients of shale gas, shale condensate, and shale oil at reservoir conditions with CO2 injection for EOR/EGR. The large nano-confinement effects including large gas-oil capillary pressure and critical property shifts could alter the phase behaviors. This study estimates the diffusivities of shale fluids in nanometer-scale shale rock from two perspectives: 1) examining the shift of diffusivity caused by nanopore confinement effects from phase change (phase composition and fluid property) perspective, and 2) calculating the effective diffusion coefficient in porous media by incorporating rock intrinsic properties (porosity and tortuosity factor). The tortuosity is obtained by using tortuosity-porosity relations as well as the measured tortuosity of shale from 3D imaging techniques. The results indicated that nano-confinement effects could affect the diffusion coefficient through altering the phase properties, such as phase compositions and densities. Compared to bulk phase diffusivity, the effective diffusion coefficient in porous shale rock is reduced by 102 to 104 times as porosity decreases from 0.1 to 0.03.
Finally, a fully compositional model is developed, which enables us to process multi-component multi-phase fluid flow in shale nano-porous media. The validation results for primary depletion, water injection, and gas injection show a good match with the results of a commercial software (CMG, GEM). The nano-confinement effects (capillary pressure effect and critical property shifts) are incorporated in the flash calculation and flow equations, and their effects on Bakken oil production and Marcellus shale gas production are examined. The results show that including oil-gas capillary pressure effect could increase the oil production but decrease the gas production. Inclusion of critical property shift could increase the oil production but decrease the gas production very slightly. The effect of molecular diffusion on Bakken oil and Marcellus shale gas production are also examined. The effect of diffusion coefficient calculated by using Sigmund correlation is negligible on the production from both Bakken oil and Marcellus shale gas huff-n-puff. Noticeable increase in oil and gas production happens only after the diffusion coefficient is multiplied by 10 or 100 times.Doctor of Philosophy
Shale reservoir is one type of unconventional reservoir and it has extremely small pore size, low porosity, and ultra-low permeability. In tight shale reservoirs, the pore size is in nanometer scale and the oil-gas capillary pressure reaches hundreds of psi. In addition, the critical properties (such as critical pressure and critical temperature) of hydrocarbon components will be altered in those nano-sized pores. In this research, two in-house reservoir simulation models, i.e., a compositionally extended black-oil model and a fully composition model are developed to examine the nano-pore confinement effects on convective and diffusive multicomponent multiphase fluid transport. The large nano-confinement effects (large gas-oil capillary pressure and critical property shifts) on oil or gas production behaviors will be investigated. Meanwhile, the nano-confinement effects and rock intrinsic properties (porosity and tortuosity factor) on predicting effective diffusion coefficient are also studied.
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Matskova, Natalia. "Approche multi-échelle pour la caractérisation de l'espace poreux des réservoirs pétroliers argileux non conventionnels." Thesis, Poitiers, 2018. http://www.theses.fr/2018POIT2276.
Full textAbstract:
Les réservoirs pétroliers argileux sont caractérisés par des systèmes de pores associés à une distribution spatiale hétérogène à plusieurs échelles des phases minérales et organiques. Cette hétérogénéité nécessite une approche multi-échelle et multi-outils pour caractériser le réseau de pores. Une telle approche a été développée grâce à la sélection rigoureuse de 7 carottes issues de la formation de Vaca Muerta (Argentine), avec différentes maturations d'hydrocarbures mais des compositions minérales comparables. La tomographie RX 3D et la cartographie de la porosité par autoradiographie ont révélé les hétérogénéités à l'échelle des carottes, et permis d'identifier des zones homogènes pour le prélèvement de sous-échantillons comparables et représentatifs.Le couplage corrélatif de différentes techniques a permis d'atteindre un bilan quantitatif de la porosité / tailles de pores et pour la première fois, sur des blocs non broyées, notamment pour les expériences d'adsorption d'azote. Les résultats d’autoradiographie sont en accord avec les autres méthodes, indiquant que tous les pores sont connectés et accessibles par la résine d’imprégnation. Une diminution de la porosité totale ainsi que des tailles de pores a également été observée avec la maturation de la matière organique.Une approche innovante pour l'acquisition et le traitement de mosaïques d’images MEB a fourni des cartographies de la distribution des phases minérales et organiques à l'échelle du cm. Le couplage corrélatif avec la carte de porosité par autoradiographie des mêmes zones, a révélé les corrélations spatiales entre variations minéralogiques et de porositéGas shale reservoirs are characterized by pore systems, associated with a heterogeneous spatial distribution of mineral and organic phases at multiple scales. This high heterogeneity requires a multi-scale & multi-tool approach to characterize the pore network. Such an approach has been developed on 7 cores from the Vaca Muerta formation (Argentina), which belong to areas with various hydrocarbon maturities, but with comparable mineral compositions. 3D µtomography and quantitative 2D mapping of the connected porosity by autoradiography have been applied at the core scale, in aim to localize and analyze the spatial heterogeneities, and to identify similar homogenous areas for localizing comparable sub-samples.The correlative coupling of various techniques was applied to achieve quantitative balance of porosity and pore size distribution, from mm to nm scales on representative sub-samples and for the first time, on preserved blocks rather than crushed powders, even for nitrogen gas adsorption experiments. Results of autoradiography are in very good agreement with other total bulk porosities, indicating that all pores are connected and accessed by the 14C-MMA used for impregnation. Decreased total porosity and pore throat/body sizes were also observed as organic matter maturity increased. An innovative approach for electron microscopy images acquisition and treatment provided large mosaics, with the distribution of mineral and organic phases at the cm scale. The correlative coupling with the autoradiography porosity map of the same zone, revealed the spatial correlations between mineralogical variations and porosity
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Bello, Rasheed O. "Rate Transient Analysis in Shale Gas Reservoirs with Transient Linear Behavior." 2009. http://hdl.handle.net/1969.1/ETD-TAMU-2009-05-316.
Full textAbstract:
Many hydraulically fractured shale gas horizontal wells in the Barnett shale have been
observed to exhibit transient linear behavior. This transient linear behavior is
characterized by a one-half slope on a log-log plot of rate against time. This transient
linear flow regime is believed to be caused by transient drainage of low permeability
matrix blocks into adjoining fractures. This transient flow regime is the only flow regime
available for analysis in many wells.
The hydraulically fractured shale gas reservoir system was described in this work
by a linear dual porosity model. This consisted of a bounded rectangular reservoir with
slab matrix blocks draining into adjoining fractures and subsequently to a horizontal well
in the centre. The horizontal well fully penetrates the rectangular reservoir. Convergence
skin is incorporated into the linear model to account for the presence of the horizontal
wellbore.
Five flow regions were identified with this model. Region 1 is due to transient
flow only in the fractures. Region 2 is bilinear flow and occurs when the matrix drainage
begins simultaneously with the transient flow in the fractures. Region 3 is the response for a homogeneous reservoir. Region 4 is dominated by transient matrix drainage and is
the transient flow regime of interest. Region 5 is the boundary dominated transient
response. New working equations were developed and presented for analysis of Regions
1 to 4. No equation was presented for Region 5 as it requires a combination of material
balance and productivity index equations beyond the scope of this work.
It is concluded that the transient linear region observed in field data occurs in
Region 4 – drainage of the matrix. A procedure is presented for analysis. The only
parameter that can be determined with available data is the matrix drainage area, Acm.
It was also demonstrated in this work that the effect of skin under constant rate
and constant bottomhole pressure conditions is not similar for a linear reservoir. The
constant rate case is the usual parallel lines with an offset but the constant bottomhole
pressure shows a gradual diminishing effect of skin. A new analytical equation was
presented to describe the constant bottomhole pressure effect of skin in a linear
reservoir.
It was also demonstrated that different shape factor formulations (Warren and
Root, Zimmerman and Kazemi) result in similar Region 4 transient linear response
provided that the appropriate f(s) modifications consistent with lAc calculations are
conducted. It was also demonstrated that different matrix geometry exhibit the same
Region 4 transient linear response when the area-volume ratios are similar.
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Freeman, Craig M. "Study of Flow Regimes in Multiply-Fractured Horizontal Wells in Tight Gas and Shale Gas Reservoir Systems." Thesis, 2010. http://hdl.handle.net/1969.1/ETD-TAMU-2010-05-7756.
Full textAbstract:
Various analytical, semi-analytical, and empirical models have been proposed to characterize rate and pressure behavior as a function of time in tight/shale gas systems featuring a horizontal well with multiple hydraulic fractures. Despite a small number of analytical models and published numerical studies there is currently little consensus regarding the large-scale flow behavior over time in such systems. The purpose of this work is to construct a fit-for-purpose numerical simulator which will account for a variety of production features pertinent to these systems, and to use this model to study the effects of various parameters on flow behavior. Specific features examined in this work include hydraulically fractured horizontal wells, multiple porosity and permeability fields, desorption, and micro-scale flow effects. The theoretical basis of the model is described in Chapter I, along with a validation of the model. We employ the numerical simulator to examine various tight gas and shale gas systems and to illustrate and define the various flow regimes which progressively occur over time. We visualize the flow regimes using both specialized plots of rate and pressure functions, as well as high-resolution maps of pressure distributions. The results of this study are described in Chapter II. We use pressure maps to illustrate the initial linear flow into the hydraulic fractures in a tight gas system, transitioning to compound formation linear flow, and then into elliptical flow. We show that flow behavior is dominated by the fracture configuration due to the extremely low permeability of shale. We also explore the possible effect of microscale flow effects on gas effective permeability and subsequent gas species fractionation. We examine the interaction of sorptive diffusion and Knudsen diffusion. We show that microscale porous media can result in a compositional shift in produced gas concentration without the presence of adsorbed gas. The development and implementation of the micro-flow model is documented in Chapter III. This work expands our understanding of flow behavior in tight gas and shale gas systems, where such an understanding may ultimately be used to estimate reservoir properties and reserves in these types of reservoirs.
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Alahmadi, Hasan Ali H. "A Triple-Porosity Model for Fractured Horizontal Wells." 2010. http://hdl.handle.net/1969.1/ETD-TAMU-2010-08-8545.
Full textAbstract:
Fractured reservoirs have been traditionally idealized using dual-porosity models.
In these models, all matrix and fractures systems have identical properties. However, it
is not uncommon for naturally fractured reservoirs to have orthogonal fractures with
different properties. In addition, for hydraulically fractured reservoirs that have preexisting
natural fractures such as shale gas reservoirs, it is almost certain that these types
of fractures are present. Therefore, a triple-porosity (dual-fracture) model is developed in
this work for characterizing fractured reservoirs with different fractures properties.
The model consists of three contiguous porous media: the matrix, less permeable
micro-fractures and more permeable macro-fractures. Only the macro-fractures produce
to the well while they are fed by the micro-fractures only. Consequently, the matrix
feeds the micro-fractures only. Therefore, the flow is sequential from one medium to the
other.
Four sub-models are derived based on the interporosity flow assumption between
adjacent media, i.e., pseudosteady state or transient flow assumption. These are fully
transient flow model (Model 1), fully pseudosteady state flow model (Model 4) and two
mixed flow models (Model 2 and 3).
The solutions were mainly derived for linear flow which makes this model the
first triple-porosity model for linear reservoirs. In addition, the Laplace domain solutions
are also new and have not been presented in the literature before in this form.
Model 1 is used to analyze fractured shale gas horizontal wells. Non-linear
regression using least absolute value method is used to match field data, mainly gas rate.
Once a match is achieved, the well model is completely described. Consequently,
original gas in place (OGIP) can be estimated and well future performance can be
forecasted.
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Jayakumar, Swathika 1986. "Hydrolyzed Polyacrylamide- Polyethylenimine- Dextran Sulfate Polymer Gel System as a Water Shut-Off Agent in Unconventional Gas Reservoirs." Thesis, 2012. http://hdl.handle.net/1969.1/149218.
Full textAbstract:
Technologies such as horizontal wells and multi-stage hydraulic fracturing have made ultra-low permeability shale and tight gas reservoirs productive but the industry is still on the learning curve when it comes to addressing various production issues. Some of the problems encountered while hydraulically fracturing these reservoirs are the absence of frac barriers, thinner shales and the increased presence of geological hazards. Induced vertical fractures sometimes extend to an underlying aquifer and become a conduit to the well. We have developed a low-concentration, low-viscosity and delayed-crosslink polymeric gel system as a water shutoff agent for hydraulically-fractured tight gas and shale reservoirs, where some fractures might connect to water rich zones. The system also is a significant improvement over traditional flowing gels for fracture water shutoff in conventional reservoirs because of these features. The gel uses high molecular weight hydrolyzed polyacrylamide (HPAM) at low polymer concentrations with a delayed organic crosslinker. This crosslinker is more environmentally benign and provides much longer gelation time and stronger final gels than comparable polymer loadings with chromium carboxylate crosslinkers at higher temperatures. The low viscosity system allows low-pressure extrusion of gelant into the narrow-aperture fractures present in unconventional gas reservoirs. The gelant can be pumped at low pressures due to lower polymer concentrations and delayed gelation point. This allows the potential to seal problem zones that are producing excess water even when the fractures conducting water have very narrow apertures. By impeding water production, the gel system developed here can effectively delay water loading thereby avoiding abandonment or installation of expensive equipment with increased operational costs, thus extending life and reserves of unconventional gas wells.
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Khan, Waqar A. "Production Trends of Shale Gas Wells." 2008. http://hdl.handle.net/1969.1/ETD-TAMU-2008-12-94.
Full textAbstract:
To obtain better well performance and improved production from shale gas
reservoirs, it is important to understand the behavior of shale gas wells and to identify
different flow regions in them over a period of time. It is also important to understand
best fracture and stimulation practice to increase productivity of wells. These objectives
require that accurate production analysis be performed. For accurate production analysis,
it is important to analyze the production behavior of wells, and field production data
should be interpreted in such a way that it will identify well parameters. This can be
done by performing a detailed analysis on a number of wells over whole reservoirs.
This study is an approach that will lead to identifying different flow regions in
shale gas wells that include linear and bilinear flow. Important field parameters can be
calculated from those observations to help improve future performance. The detailed
plots of several wells in this study show some good numbers for linear and bilinear flow,
and some unique observations were made. The purpose of this work is to also manage
the large amount of data in such a way that they can be used with ease for future studies.
A program was developed to automate the analysis and generation of different plots. The
program can also be used to perform the simple calculations to calculate different parameters. The goal was to develop a friendly user interface that would facilitate
reservoir analysis.
Examples were shown for each flow period, i.e. linear and bilinear flow.
Different plots were generated (e.g; Bob Plot (square root of time plot) and Fourth Root
of Time Plot, that will help in measuring slopes and thus reservoir parameters such as
fracture permeability and drainage area. Different unique cases were also observed that
show a different behavior of well in one type of plot from another.
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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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Tzu-JungYang and 楊慈容. "Study of Production Characteristics of Shale Gas Reservoirs." Thesis, 2013. http://ndltd.ncl.edu.tw/handle/17580850771097069631.
Full textAbstract:
碩士國立成功大學
資源工程學系碩博士班
101
Shale gas has the most development potential of unconventional gas resources. In shale gas reservoirs, the gas is stored both as free gas in the pore volume of natural fractures and the rock matrix, and as adsorbed gas on the surface of organic matter. Because of the ultra-low permeability of shale, hydraulic fracturing and horizontal wells are used for production. The purpose of this study is to use the numerical simulation method to study the effect of flowing bottomhole pressure (BHP), production rate, and the flow regimes of shale gas reservoirs on different reservoir types (single- and dual- porosity systems), gas-flow mechanisms (adsorption and diffusion), and well completion methods (vertical well, horizontal well, and hydraulic fracturing).The estimated ultimate recovery (EUR) and production years were examined by assuming different abandonment pressures or rates. A single-porosity model was first established to study the effect of BHP and production rate on different well completion methods, and then a dual-porosity model, to study the effect of BHP and production rate on different well completion methods and the adsorption and diffusion mechanisms. To study gas-flow regimes, both the pressure-derivative and reciprocal-rate derivative methods were used. The following results (EUR and production characteristics) were obtained from a reservoir with average properties from literature. Estimated Ultimate Recovery (EUR) results were: (1) for single-porosity system, the EURs of the vertical, horizontal, fractured vertical, and the single-fractured horizontal wells were very low except the three-fractured horizontal well. For constant-rate production (800MScf/day), the three-fractured horizontal well was 1.9 and 2.6Bcf at the abandonment pressures of 1500and 1000psi, respectively. For constant pressure ( psi) production, the three-fractured horizontal well was 1.2 and 1.8Bcf at the abandonment rates of 100 and 50MScf/day. (2) For dual-porosity constant-rate production, EUR ranges were of 10.4~20.7Bcf and 13.9~26Bcf at the abandonment pressures of 1500 and 1000psi. The three-fractured horizontal well had the highest value, then the single-fractured horizontal, fractured vertical, horizontal, and vertical wells. For constant-pressure production, EUR ranges were 5.8~6.8Bcf and 6.3~6.8Bcf at the abandonment rates of 100 and 50MScf/day. (3) For dual-porosity considering gas adsorption and diffusion constant-rate production, EUR ranges were 11.4~23.6Bcf and 15.3~30.6Bcf at the abandonment pressures of 1500 and 1000psi. For constant-pressure production, EUR ranges were 6.3~7.4Bcf and 6.9~7.4Bcf at the abandonment rates of 100 and 50MScf/day. (4) Gas could not be produced using the ultra-low permeability single-porosity system without hydraulic fracturing. The EUR of the vertical-fractured well was similar to that of the single-fractured horizontal well, but the fracture size and permeability were the same. Three-fractured horizontal well had higher EUR than did single-fractured horizontal well. Production characteristics were: (1) BHP, production-rate behavior, and flow regimes of vertical-fractured and single-fractured horizontal wells were almost the same. The slope of the pressure-derivative plot was 0.64 because of the pressure interference between adjacent fractures during production from three-fractured horizontal well. (2) Transition time in dual-porosity systems of different well completions can be determined from both the pressure- and the reciprocal-rate derivative plots, which shows that hydraulic fracturing has no effect on transition periods. (3) Gas adsorption and diffusion mechanisms had little effect on Barnett shale during production; therefore, shale gas production behavior can be directly modeled using the dual-porosity system.
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Mengal, Salman Akram. "Accounting for Adsorbed gas and its effect on production bahavior of Shale Gas Reservoirs." 2010. http://hdl.handle.net/1969.1/ETD-TAMU-2010-08-8446.
Full textAbstract:
Shale gas reservoirs have become a major source of energy in recent years.
Developments in hydraulic fracturing technology have made these reservoirs more
accessible and productive. Apart from other dissimilarities from conventional gas
reservoirs, one major difference is that a considerable amount of gas produced from
these reservoirs comes from desorption. Ignoring a major component of production, such
as desorption, could result in significant errors in analysis of these wells. Therefore it is
important to understand the adsorption phenomenon and to include its effect in order to
avoid erroneous analysis.
The objective of this work was to imbed the adsorbed gas in the techniques used
previously for the analysis of tight gas reservoirs. Most of the desorption from shale gas
reservoirs takes place in later time when there is considerable depletion of free gas and
the well is undergoing boundary dominated flow (BDF). For that matter BDF methods,
to estimate original gas in place (OGIP), that are presented in previous literature are
reviewed to include adsorbed gas in them. More over end of the transient time data can also be used to estimate OGIP. Kings modified z* and Bumb and McKee’s adsorption
compressibility factor for adsorbed gas are used in this work to include adsorption in the
BDF and end of transient time methods.
Employing a mass balance, including adsorbed gas, and the productivity index
equation for BDF, a procedure is presented to analyze the decline trend when adsorbed
gas is included. This procedure was programmed in EXCEL VBA named as shale gas
PSS with adsorption (SGPA). SGPA is used for field data analysis to show the
contribution of adsorbed gas during the life of the well and to apply the BDF methods to
estimate OGIP with and without adsorbed gas. The estimated OGIP’s were than used to
forecast future performance of wells with and without adsorption.
OGIP estimation methods when applied on field data from selected wells showed
that inclusion of adsorbed gas resulted in approximately 30 percent increase in OGIP estimates
and 17 percent decrease in recovery factor (RF) estimates. This work also demonstrates that
including adsorbed gas results in approximately 5percent less stimulated reservoir volume
estimate.
44
Olorode, Olufemi Morounfopefoluwa. "Numerical Modeling of Fractured Shale-Gas and Tight-Gas Reservoirs Using Unstructured Grids." Thesis, 2011. http://hdl.handle.net/1969.1/ETD-TAMU-2011-12-10286.
Full textAbstract:
Various models featuring horizontal wells with multiple induced fractures have been proposed to characterize flow behavior over time in tight gas and shale gas systems. Currently, there is little consensus regarding the effects of non-ideal fracture geometries and coupled primary-secondary fracture interactions on reservoir performance in these unconventional gas reservoirs.
This thesis provides a grid construction tool to generate high-resolution unstructured meshes using Voronoi grids, which provides the flexibility required to accurately represent complex geologic domains and fractures in three dimensions. Using these Voronoi grids, the interaction between propped hydraulic fractures and secondary "stress-release" fractures were evaluated. Additionally, various primary fracture configurations were examined, where the fractures may be non-planar or non-orthogonal.
For this study, a numerical model was developed to assess the potential performance of tight gas and shale gas reservoirs. These simulations utilized up to a half-million grid-blocks and consider a period of up to 3,000 years in some cases. The aim is to provide very high-definition reference numerical solutions that will exhibit virtually all flow regimes we can expect in these unconventional gas reservoirs. The simulation results are analyzed to identify production signatures and flow regimes using diagnostic plots, and these interpretations are confirmed using pressure maps where useful.
The coupled primary-secondary fracture systems with the largest fracture surface areas are shown to give the highest production in the traditional "linear flow" regime (which occurs for very high conductivity vertical fracture cases). The non-ideal hydraulic fracture geometries are shown to yield progressively lower production as the angularity of these fractures increases. Hence, to design optimum fracture completions, we should endeavor to keep the fractures as orthogonal to the horizontal well as possible.
This work expands the current understanding of flow behavior in fractured tight-gas and shale-gas systems and may be used to optimize fracture and completion design, to validate analytical models and to facilitate more accurate reserves estimation.
45
Po-TingLin and 林柏廷. "Decline Curve Analysis of Tight Sand/Shale Gas Reservoirs." Thesis, 2014. http://ndltd.ncl.edu.tw/handle/13451197053857445263.
Full textAbstract:
碩士國立成功大學
資源工程學系
102
Duong’s method of forecasting production and estimated ultimate recovery (EUR) in low permeability reservoirs with a long-term linear flow has been verified by several authors. However, Duong’s method overestimates future production during boundary-dominated flow. It is reasonable to combine Duong’s method and the Arps decline relations for fractured wells exhibited linear flow followed by boundary-dominated flow, because the Arps decline relation has better prediction for boundary-dominated flow. For wells that have not reached boundary-dominated flow, Wattenbarger et al.’s linear flow theory is frequently used to determine the duration of linear flow, and the end of linear flow time (telf) can be used to estimate when to switch from Duong’s method to the Arps decline relation. This paper focuses on the availability of the end of linear flow time determined by linear flow theory with a hybrid forecasting method, which combines Duong’s method and the Arps exponential relation for tight sand/shale gas reservoirs. To obtain the proper end of linear flow time, modified Wattenbarger et al.’s analytical solution and modified empirical solutions (Duong’s method combines the Arps exponential relation) was derived. The golden section search method is used to find the modified end of linear flow time that minimizes the difference between modified analytical and empirical solutions. Then, the hybrid forecasting method was used to forecast production of synthetic production data generated from an analytical solution. A number of cases were tested to verify the efficacy of this method for forecasting production. To account for tight sand/shale gas reservoirs, reservoir permeability ranging from 10-1 md to 10-4 md was considered. The results indicated that the hybrid forecasting method used with the modified end of linear flow time is theoretically accurate for production forecast and EUR estimation. In low-permeability reservoirs with a permeability ranging from 10-1 md to 10-3 md, this method provides a significant improvement in EUR estimation. Finally, application of this method to field examples from Barnett shale gas and Bossier sand gas were also presented.
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Huynh, Uyen T. "Surfactant characterization to improve water recovery in shale gas reservoirs." Thesis, 2013. http://hdl.handle.net/2152/23798.
Full textAbstract:
After a fracturing job in a shale reservoir, only a fraction of injected water is recovered. Water is trapped inside the reservoir and reduces the relative permeability of gas. By reducing the interfacial tension between water and hydrocarbon, more water can be recovered thus increasing overall gas production. By adding surfactants into the fracturing fluid, the IFT can be reduced and will help mobilize trapped water. From previous research, two types of surfactant have been identified to be CO₂ soluble. These are the ethoxylated tallow amine and ethoxylated coco amine with varying ethoxylate length. Experiments were performed to test the solubility of these surfactants in water, observe how they change the interaction between HC and water, and measure the IFT reduction between HC and water. Surfactants with more than 10 EO groups were soluble at all salinities, temperature and pH. They also form a non-typical water-in-oil emulsion at all salinities. The surfactants, Ethomeen T/25, T/30, C/15, and C/25 were used in the IFT measurements. They showed interesting trends that exhibit their hydrophilic/hydrophobic nature. These surfactants reduce the IFT between pentane and water to approximately 5 mN/m. The results show that these surfactants do reduce the IFT between water and hydrocarbon, but not as well as conventional EOR surfactants. They do have other added benefits such as being CO₂ soluble, form water in oil emulsions, and tolerant to high temperature and salinity.text
47
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
48
Huang, Jian. "Geomechanical Development of Fractured Reservoirs During Gas Production." Thesis, 2013. http://hdl.handle.net/1969.1/149448.
Full textAbstract:
Within fractured reservoirs, such as tight gas reservoir, coupled processes between matrix deformation and fluid flow are very important for predicting reservoir behavior, pore pressure evolution and fracture closure. To study the coupling between gas desorption and rock matrix/fracture deformation, a poroelastic constitutive relation is developed and used for deformation of gas shale. Local continuity equation of dry gas model is developed by considering the mass conservation of gas, including both free and absorbed phases. The absorbed gas content and the sorption-induced volumetric strain are described through a Langmiur-type equation. A general porosity model that differs from other empirical correlations in the literature is developed and utilized in a finite element model to coupled gas diffusion and rock mass deformation.
The dual permeability method (DPM) is implemented into the Finite Element Model (FEM) to investigate fracture deformation and closure and its impact on gas flow in naturally fractured reservoir. Within the framework of DPM, the fractured reservoir is treated as dual continuum. Two independent but overlapping meshes (or elements) are used to represent these kinds of reservoirs: one is the matrix elements used for deformation and fluid flow within matrix domain; while the other is the fracture element simulating the fluid flow only through the fractures. Both matrix and fractures are assumed to be permeable and can accomodate fluid transported. A quasi steady-state function is used to quantify the flow that is transferred between rock mass and fractures. By implementing the idea of equivalent fracture permeability and shape-factor within the transfer function into DPM, the fracture geometry and orientation are numerically considered and the complexity of the problem is well reduced. Both the normal deformation and shear dilation of fractures are considered and the stress-dependent fracture aperture can be updated in time.
Further, a non-linear numerical model is constructed by implementing a poroviscoelastic model into the dual permeability (DPM)-finite element model (FEM) to investigate the coupled time-dependent viscoelastic deformation, fracture network evolution and compressible fluid flow in gas shale reservoir. The viscoelastic effect is addressed in both deviatoric and symmetric effective stresses to emphasize the effect of shear strain localization on fracture shear dilation. The new mechanical model is first verified with an analytical solution in a simple wellbore creep problem and then compared with the poroelastic solution in both wellbore and field cases.
49
Agnia, Ammar Khalifa Mohammed. "Data Bias in Rate Transient Analysis of Shale Gas Wells." Thesis, 2012. http://hdl.handle.net/1969.1/ETD-TAMU-2012-05-10853.
Full textAbstract:
Superposition time functions offer one of the effective ways of handling variable-rate data. However, they can also be biased and misleading the engineer to the wrong diagnosis and eventually to the wrong analysis. Since the superposition time functions involve rate as essential constituent, the superposition time is affected greatly with rate issues. Production data of shale gas wells are usually subjected to operating issues that yield noise and outliers. Whenever the rate data is noisy or contains outliers, it will be hard to distinguish their effects from common regime if the superposition time functions are used as plotting time function on log-log plots. Such deceiving presence of these flow regimes will define erroneous well and reservoir parameters. Based on these results and with the upsurge of energy needs there might be some costly decisions will be taken such as refracting or re-stimulating the well especially in tight formations.
In this work, a simple technique is presented in order to rapidly check whether there is data bias on the superposition-time specialized plots or not. The technique is based on evaluating the kernel of the superposition time function of each flow regime for the maximum production time. Whatever beyond the Kernel-Equivalent Maximum Production Time (KEMPT) it is considered as biased data. The hypothesis of this technique is that there is no way to see in the reservoir more than what has been seen. A workflow involving different diagnostic and filtering techniques has been proposed to verify proposed notion. Different synthetic and field examples were used in this study.
Once the all problematic issues have been detected and filtered out, it was clear that whatever went beyond the KEMPT is a consequence of these issues. Thus, the proposed KEMPT technique can be relied on in order to detect and filter out the biased data points on superposition-time log-log plots. Both raw and filtered data were analyzed using type-curve matching of linear flow type-curves for calculating the original gas in-place (OGIP). It has been found that biased data yield noticeable reduced OGIP. Such reduction is attributed to the early fictitious onset of boundary dominated flow, where early false detection of the drainage boundaries defines less gas in-place occupied in these boundaries.
50
Apiwathanasorn, Sippakorn. "Evidence of Reopened Microfractures in Production Data of Hydraulically Fractured Shale Gas Wells." Thesis, 2012. http://hdl.handle.net/1969.1/ETD-TAMU-2012-08-11749.
Full textAbstract:
Frequently a discrepancy is found between the stimulated shale volume (SSV) estimated from production data and the SSV expected from injected water and proppant volume. One possible explanation is the presence of a fracture network, often termed fracture complexity, that may have been opened or reopened during the hydraulic fracturing operation.
The main objective of this work is to investigate the role of fracture complexity in resolving the apparent SSV discrepancy and to illustrate whether the presence of reopened natural fracture network can be observed in pressure and production data of shale gas wells producing from two shale formations with different well and reservoir properties.
Homogeneous, dual porosity and triple porosity models are investigated. Sensitivity runs based on typical parameters of the Barnett and the Horn River shale are performed. Then the field data from the two shales are matched.
Homogeneous models for the two shale formations indicate effective infinite conductivity fractures in the Barnett well and only moderate conductivity fractures in the Horn River shale. Dual porosity models can support effectively infinite conductivity fractures in both shale formations.
Dual porosity models indicate that the behavior of the Barnett and Horn River shale formations are different. Even though both shales exhibit apparent bilinear flow behavior the flow behaviors during this trend are different. Evidence of this difference comes from comparing the storativity ratio observed in each case to the storativity ratio estimated from injected fluid volumes during hydraulic fracturing. In the Barnett shale case similar storativity ratios suggest fracture complexity can account for the dual porosity behavior. In the Horn River case, the model based storativity ratio is too large to represent only fluids from hydraulic fracturing and suggests presence of existing shale formation microfractures.