Dissertations / Theses on the topic 'Gas shales'

An inter-laboratory study of high-pressure gas sorption measurements on two carbonaceous shales has been conducted to assess the reproducibility of sorption isotherms on shale and identify possible sources of error. The measurements were carried out by 7 different international research laboratories on either in-house or commercial sorption equipment using manometric as well as gravimetric methods. Excess sorption isotherms for methane, carbon dioxide and ethane were measured at 65°C and at pressures up to 25 MPa on two organic-rich shales at dry conditions. The inter-laboratory reproducibility of the methane excess sorption isotherms was better for the high-maturity shale (within 0.02 – 0.03 mmol g-1) than for the low-maturity sample (up to 0.1 mmol g-1), which is in agreement with results of earlier studies on coals. The procedures for sample conditioning prior to the measurement, the measurement procedures and the data reduction approach must be optimized to achieve higher accuracy. Unknown systematic errors in the measured quantities must be minimized first by applying standard calibration methods. Furthermore, the adsorption of methane on a dry, organic-rich, high-maturity Alum shale sample was studied at a wide temperature range (300 – 473 K) and pressures up to 14 MPa. These conditions are relevant to gas storage under geological conditions. Maximum methane excess uptake is 0.176 – 0.042 mmol g-1 (125 - 30 scf t-1) at 300 - 473 K. Supercritical adsorption was parameterized using the modified Dubinin-Radushkevich and the Langmuir equations. Gas in shales is stored in three different states: adsorbed, compressed (free) and dissolved; quantifying each underpins calculations of gas storage capacity and also the mechanisms by which gas must be transported from pore (surfaces), to fracture, to the well. While compressed gas dominates in meso- and macropores, it is often assumed that (a) sorbed gas occurs mainly in micropores (< 2nm) and (b) micropores are mainly associated with organic matter. In the third part of this thesis, those ideas are tested by characterising the porous structure of six shales and isolated kerogens from the Posidonia Formation in combination with high pressure methane sorption isotherms at 45, 65 and 85°C. Together, these data help us to understand the extent to which (a) small pores control CH4 sorption and (b) whether “sorption” pores are associated with the organic and inorganic phases within shales. Samples were selected with vitrinite reflectance of 0.6, 0.9 and 1.45%. Pore volumes – named sorption pore volumes here - were determined on dry shales and isolated kerogens by CO2 isotherms measured at -78°C and up to 0.1 MPa. These volumes include micropores (pore II width < 2nm) and narrow mesopores; according to the Gurvitch Rule this is the volume available for sorption of most gases. Sorption pore volumes of Posidoniashales range from 0.008 to 0.016 cm3 g-1, accounting for 21 - 66% of total porosity. Whilst sorption pore volumes of isolated kerogen are much higher, between 0.095 – 0.147 cm3 g-1, normalization by TOC shows that only half the sorption pore volume of the shales is located within the kerogen. Excess uptakes on dry Posidonia shales at 65°C and 11.5MPa range from 0.056−0.110 mmol g-1 (40−78 scf t-1) on dry shale, and from 0.36−0.70 mmol g-1 (253−499 scf t-1) on dry kerogen. Enthalpies of adsorption show no variation with TOC and maturity, respectively. The correlation between maximum CH4 sorption and CO2 sorption pore volume at 195 K is very strong and goes through the origin, suggesting that the vast majority of sorbed CH4 occurs in pores smaller than 6 nm. Approximately half the sorption pore volume and thus CH4 sorption potential of these dry shales is in organic matter, with the rest likely to be associated with clay minerals. Sorption mass balances using isotherms for kerogen and clay minerals do not always account for the total measured sorbed CH4 on dry shales, suggesting that some sorption may occur at interfaces between minerals and organic matter.

The mechanical properties and matrix permeability of gas shales are the most important properties in determining their production capacity. In this research, I have investigated the matrix permeability and rock mechanical properties of Western Canadian and Woodford shales. The matrix permeability was measured using pulse decay experiment. The pulse decay experiment was employed with triaxial experiments combined with mercury porosimetry, helium pydnometry, Rock-Eval pyrolysis, SEM and X-ray diffraction analysis to measure rock strength, pore size, porosity, total organic content, fabric and composition of samples. The permeability results were correlated with effective stress, anisotropy, fabric, rock strength, porosity, pore size and total organic content. Mineralogy plays an important role in determining the permeability of Canadian and Woodford shales. Higher permeability was observed in samples with high clay content, and low permeability was observed in samples with high quartz and carbonate content. Among the clay-, silica-, and calcite-rich Canadian shales, the calcite-rich shales had a very low permeability (1O⁻⁷ md) compared to other shales. The permeability of all shales decline exponentially with increasing effective stress. Samples that were tested parallel to bedding had higher permeabilities than samples were tested normal to bedding. Among shales, the quartz-rich shales showed differences of three to four orders of magnitude for the samples tested parallel to bedding, compared to those tested normal to the bedding. The largest anisotropy was found in the clay-rich samples. Clay-rich shales also have a well developed fabric with a strongly preferred orientation, while the quartz-rich shales had random orientation of the fabric. The porosimetry results suggest that fluid flow is mostly in the meso (2-50 nm) and macro pores (>50 nm) of the Woodford shales. Samples with higher clay content (>30%) showed a higher intrusion volume in macro pores, while samples with higher quartz content showed intrusion volume in micro pores. Porosity is correlated to permeability in the Western Canadian shales and showed a linear correlation within the Woodford shales. Even though calcite-rich Canadian shales and quartz-rich Woodford shales have high TOC content, TOC was not seen to effect permeability. Triaxial compression rock testing was conducted on the Woodford shales to measure the elastic properties and strength behaviour of shale. Lithologic composition plays an important role in the strength and pore compressibility of shale. Quartz-rich or carbonate rich shales have a brittle behaviour and clay-rich shales have a ductile behaviour. Pore compressibility is greater in the clay-rich shales, and less in the quartz-rich shales.

In this study, imbibition experiments are used to explain the significant fluid loss, often more than 70%, of injected water during well stimulation and flowback in the context of natural gas production from shale formations. Samples from a 180 ft. long section of a vertical well were studied via spontaneous and forced imbibition experiments, at lab-scale, on small samples with characteristic dimensions of a few cm; in order to quantify the water imbibed by the complex multi-porosity shale system. The imbibition process is, typically, characterized by a distinct transition from an initial linear rate (vs. square root of time) to a much slower imbibition rate at later times. These observations along with contact angle measurements provide an insight into the wettability characteristics of the shale surface. Using these observations, together with an assumed geometry of the fracture system, has made it possible to estimate the distance travelled by the injected water into the formation at field scale.

Shale characterization experiments including permeability measurements, total organic carbon (TOC) analysis, pore size distribution (PSD) and contact angle measurements were also performed and were combined with XRD measurements in order to better understand the mass transfer properties of shale. The experimental permeabilities measured in the direction along the bedding plane (10 ^–1–10^–2 mD) and in the vertical direction (~10^–4 mD) are orders of magnitude higher than the matrix permeabilities of these shale sample (10^–5 to 10 ^–8 mD). This implies that the fastest flow in a formation is likely to occur in the horizontal direction, and indicates that the flow of fluids through the formation occurs predominantly through the fracture and micro-fracture network, and hence that these are the main conduits for gas recovery. The permeability differences among samples from various depths can be attributed to different organic matter content and mineralogical characteristics, likely attributed to varying depositional environments. The study of these properties can help ascertain the ideal depth for well placement and perforation.

Forced imbibition experiments have been carried out to better understand the phenomena that take place during well stimulation under realistic reservoir conditions. Imbibition experiments have been performed with real and simulated frac fluids, including deionized (DI) water, to establish a baseline, in order to study the impact on imbibition rates resulting from the presence of ions/additives in the imbibing fluid. Ion interactions with shales are studied using ion chromatography (IC) to ascertain their effect on imbibition induced porosity and permeability change of the samples. It has been found that divalent cations such as calcium and anions such as sulfates (for concentrations in excess of 600 ppm) can significantly reduce the permeability of the samples. It is concluded, therefore, that their presence in stimulating fluids can affect the capillarity and fluid flow after stimulation. We have also studied the impact of using fluoro-surfactant additives during spontaneous and forced imbibition experiments. A number of these additives have been shown to increase the measured contact angles of the shale samples and the fluid recovery from them, thus making them an ideal candidate for additives to use. Their interactions with the shale are further characterized using the Dynamic Light Scattering (DLS) technique in order to measure their hydrodynamic radius to compare it with the pore size of the shale sample.

The search for onshore oil and gas in Britain has had an erratic pattern of historical development but since the discovery of the Wytch Farm field in Dorset, during 1973, the industry has undergone a marked revival. Over the past ten years one of the highest levels of exploration ever experienced has been achieved and this has raised a number of interesting new questions in relation to planning for these developments. One of the main problems is that although the drilling of an exploratory borehole requires planning permission the work itself is only a temporary operation and on the basis of this argument permission has been sought to drill wells on land of high amenity or ecological value. However, a successful exploratory borehole can lead to a planning application for the installation of more permanent production facilities and this can lead to something of a dilemma for planners as to where exploratory drilling should be permitted. This research aimed to investigate the onshore hydrocarbons industry and determine what were the impacts of and the issues raised by this new phase of activity. The work was given an exciting new dimension when a public inquiry was called to investigate Shell UK's planning application to sink an exploratory borehole in the New Forest. The proceedings of the Inquiry were followed and the evidence presented was used to help determine the important issues. A series of detailed interviews were then undertaken to illuminate the problems from the viewpoint of both the industry and the planners. Mineral Planning Officers and Oil Company Officials answered similar questions and related these to their own individual experiences of onshore hydrocarbons operations. The research concluded that although the industry raised a number of problems the use of effective planning control at both central and local levels could overcome most of these. A series of recommendations were made.

A multi-disciplinary research project including experimental and modelling studies was carried out on shale samples to characterise their porosity and permeability. Pressure expansion techniques were used, including current industry-standard methods as well as new methods developed and modified throughout this research. The derived porosity and permeability values were cross-checked with the results from commercial laboratories. Finally, the results obtained were applied to a shale resource play currently being appraised to understand its commercial viability. Precise grain density results were achieved using the crushed shale method as helium is able to rapidly intrude small sample pores and is not significantly adsorbed onto the constituents of the shale. Precise bulk volume measurements were obtained using mercury immersion but these are ambient stress measurements and need correcting for in-situ conditions. Mercury probably does not enter the pore-space of shale at low pressures during MICP tests and instead closes artificial microfractures. So the results may provide a method to estimate bulk density at the reservoir stresses. The porosity measured using the crushed shale method is more accurate compared to core plug methods. It is important to dry crushed samples to standardise porosity measurements. Other laboratories produced comparable results except for one laboratory which most likely did not conduct sample cleaning procedures properly. Permeability values obtained using the crushed shale method were orders of magnitudes different between the measurements conducted during this study and commercial laboratories. Overall, this test appears to provide no useful information regarding the flow properties of shales. Measurements made on core plugs are often dominated by the presence of microfractures but it is possible to obtain reasonably reliable permeability estimates by inverting the experimental data using a dual porosity-permeability model. To assess the applicability of porosity and permeability methods on commercial shale play, a significant amount of in-situ field data (i.e. well tests, core data etc.) were gathered and tested during the collaborative project in Europe with a local gas exploration company. Gas-In-Place (GIP) and Estimated Ultimate Recovery (EUR) values were produced and based on these the project was approved by the company for the next stage of development. However the model constructed lacked the ability to reproduce the well flow production rates.

This thesis describes the advantages of investigating gas shales reservoir description on a nanoscale by using petrographic analysis and core plug petrophysics to characterize the Barnett, Marcellus and Mancos shale plays. The results from this analysis now indicate their effects on the reservoir quality. Helium porosity measurements at confining pressure were carried out on core plugs from this shale plays. SEM (Scanning Electron Microscopy) imaging was done on freshly fractured gold-coated surfaces to indicate pore structure and grain sizes. Electron Dispersive X-ray Spectroscopy was done on freshly fractured carbon-coated surfaces to tell the mineralogy. Extra-thin sections were made to view pore spaces, natural fractures and grain distribution.

The results of this study show that confining pressure helium porosity values to be 9.6%, 5.3% and 1.7% in decreasing order for the samples from the Barnett, Mancos and Marcellus shale respectively. EDS X-ray spectroscopy indicates that the Barnett and Mancos have a high concentration of quartz (silica-content); while the Mancos and Marcellus contain calcite. Thin section analysis reveals obvious fractures in the Barnett, while Mancos and Marcellus have micro-fractures.

Based on porosity, petrographic analysis and mineralogy measurements on the all the samples, the Barnett shale seem to exhibit the best reservoir quality.

This research provides a multiscale geomechanical characterization workflow for ultra-tight and anisotropic Goldwyer gas shales by integrating field appraisal, laboratory deformation and ultrasonic testing, viscoelastic modelling, and hydraulic fracture simulation. The outcome of this work addresses few of the practical challenges in unconventional reservoirs including but not limited to (i) microstructure & compositional control on rock mechanical properties, (ii) robust estimation of elastic anisotropy, (iii) viscous stress relaxation to predict the least principal stress Shmin at depth from creep, (iv) influence of specific surface area on creep, and (v) impact of stress layering on hydraulic fracturing design.

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

Thesis (M.S.)--West Virginia University, 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).

Processing of Bolu-Himmetoglu (Type I Kerogen) and Ankara-Beypazari (Type II Kerogen) oil shales by flotation techniques were investigated for achieving clean solid fuel substitutes. Materials characterization was done through mineralogical, XRD and FTIR analyses. Flotation responses of the samples were tested with non-ionizing and ionizing collectors of cationic and anionic types. The effects of the collector dosage and pulp pH on cleaning were determined. Other important flotation parameters, conditioning time, flotation time, pulp density, particle size and frother dosage were encountered using a statistical approach, through a full two level factorial experimental design. An advanced flotation procedure, assisted by ultrasonic application, was developed for further improvement in flotation performance. The effects of cleaning on thermal characterstics and combustion kinetics were evaluated with Differential Scanning Calorimetry and ASTM methods while the changes in the emission profiles were assessed using Effluent Gas Analysis. Himmetoglu sample was characterized as a carbonate and organic rich humic oil shale with XRD and FTIR analyses while Beypazari oil shale involved significant carbonate and clay minerals and exhibited a fulvic character with a poor organics content. Reverse flotation with amine acetates provided the most effective means of cleaning with Himmetoglu oil shale. Ash was decreased from 34.76 % to 23.52 % with a combustible recovery of 83.57 % using 800 g/ton Flotigam CA at natural pH and the calorific value increased from 4312 kcal/kg to 5010 kcal/kg. Direct flotation with amines was most effective for Beypazari oil shale cleaning. Using Armoflote 17, ash was reduced from 69.88 % to 53.10 % with 58.64 % combustible recovery using 800 g/ton Armoflote 17 at natural pulp pH and the calorific value of the sample increased from 876 kcal/kg to 2046 kcal/kg. Following optimization, ash of Himmetoglu oil shale decreased to 16.81 % with 84.10 % combustible recovery and calorific value increased to 5564 kcal/kg. For Beypazari oil shale ash decreased to % 48.42 with 59.17 % combustible recovery and the calorific value increased to 2364 kcal/kg. Ultrasonic pre-treatment before flotation further decreased the ash of Himmetoglu sample to 11.82 % with 82.66 % combustible recovery at 15 minutes pre-conditioning time and 50 % power level. For Beypazari oil shale, ash decreased to 34.76 % with 64.78 % combustible recovery after 15 minutes pre-treatment time at 70 % power level. Comparative XRD spectra and SEM analyses revealed that the extent of mineral matter removal relied on the flotation performance. The thermal indicators considerably improved after cleaning and the extent of improvement increased with a decrease in the ash of the concentrates. Kinetic analysis showed the favorable effect of inorganics removal on the effectiveness and easiness of combustion and activation energies decreased after cleaning for both oil shales. The contributions of cleaning on the effectiveness of combustion were also revealed by the increases in the emission rates and total CO2 and CO emission amounts. CO2 emissions due to mineral matter decomposition and harmful SO2 emissions apparently decreased as a consequence of the cleaning of the undesired inorganic contituents and potentially cleaning components. Results of the cleaning and thermal analysis sudies revealed that it was possible to achieve a clean energy source alternative from oil shales through flotation and a significant potential can be anticipated for future use of oil shales as a cost effective and environmental friendly solid fuel substitute in view of Turkey&
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s great oil shale reserves.

2011/2012
Un materiale si definisce isotropico quando le sue proprietà non cambiano in funzione della direzione secondo cui vengono misurate. Al contrario, se il mezzo è caratterizzato da una dipendenza direzionale delle sue proprietà, è chiamato anisotropico. Tradizionalmente, l’esplorazione sismica è basata sul processamento e interpretazione di dati acustici relativi a mezzi considerati sismicamente isotropici. Tuttavia, l’isotropia è sempre un modello approssimato per descrivere le formazioni geologiche, specialmente nel caso di bacini sedimentari. L’imaging sismico e la stima delle velocità sismiche nel sottosuolo risultano essere inaccurati quando dati relativi a mezzi anisotropici vengono processati con l’assunzione di isotropia. Conseguentemente è importante definire il modello e l’intensità dell’anisotropia che contraddistinguono l’area in esame e utilizzare queste informazioni per il processamento dei dati sismici. Lo scopo principale di questo studio consiste nella caratterizzazione dell’anisotropia degli scisti bituminosi del giacimento di Abbott, presenti nel Bacino di Arkoma, Oklahoma, USA. I dati consistono in registrazioni sismiche ottenute da due stendimenti di superficie composti da geofoni a sola componente verticale e da accelerometri a tre componenti, acquisite durante la fratturazione idraulica del giacimento. Il monitoraggio sismico di superficie è generalmente meno costoso se comparato al monitoraggio da pozzo, specialmente quando i pozzi di osservazione non sono disponibili e devono essere perforati. La tecnica da superficie è basata sull’acquisizione di dati sismici da centinaia di ricevitori opportunamente distribuiti al suolo ed offre una visione del campo d’onda molto più ampia rispetto al monitoraggio da pozzo, generalmente limitato a qualche decina di ricevitori vicini tra loro. Inoltre, l’analisi dei tempi di arrivo di dati acquisiti da reti di ricevitori di superficie costituisce un metodo più robusto rispetto agli studi di polarizzazione di cui sono oggetto i dati di monitoraggio sismico da pozzo. L’inconveniente è un rapporto segnale rumore sensibilmente più basso a causa delle eterogeneità geologiche presenti in prossimità della superficie. Durante il trattamento degli scisti bituminosi di Abbott, è stato registrato qualche centinaio di eventi microsismici e di questi sono stati analizzati i dieci eventi più forti, oltre che i dati derivanti da scoppi di perforazione. La Vertical Transverse Isotropy (VTI) è, senza dubbio, il modello anisotropico più comune in bacini sedimentari, specialmente in presenza di scisti. La velocità sismica in mezzi VTI varia quando la direzione di propagazione si discosta dalla verticale ma non al variare dell’azimut. L’analisi dei dati sismici relativi alle onde P ha confermato che il modello VTI è quello che meglio si adatta agli scisti di Abbott e/o alle rocce sovrastanti. In mezzi omogenei ed anisotropici di tipo VTI i tempi di arrivo delle onde P ed S si discostano dal moveout iperbolico, che invece caratterizza la propagazione in mezzi omogenei ed isotropici. La non-iperbolicità dei tempi di percorso delle onde sismiche può essere utilizzata per la stima dei parametri di anisotropia. I tempi di arrivo ottenuti dai dati sperimentali possono essere approssimati attraverso l’utilizzo di equazioni analitiche che esprimono i tempi di percorso in funzione dei suddetti parametri di anisotropia. Questa tecnica di inversione è stata testata con dati sintetici e successivamente applicata ai dati del giacimento di Abbott. Dai tempi di arrivo delle onde P ed SH di dieci eventi microsismici sono stati stimati i tre parametri di anisotropia di Thomsen, mentre per quattro scoppi di perforazione è stata applicata l’inversione delle sole onde compressionali. Inoltre è stata accuratamente analizzata la sensibilità del metodo alla presenza di rumore e di eventuale inaccuratezza dei parametri di input. Le inversioni dei tempi di arrivo delle onde P prodotte dagli scoppi di perforazione forniscono parametri di anisotropia tra loro consistenti, mentre i risultati dai tempi di arrivo delle onde compressionali e di taglio relativi agli eventi microsismici sono caratterizzati da una moderata dispersione. Questo risultato può essere spiegato dalla minore accuratezza e più ampia distribuzione spaziale delle sorgenti microsismiche, se paragonate agli scoppi di perforazione. Inoltre, le proprietà elastiche del volume di roccia nell’intorno di ciascuna sorgente microsismica, così come le sue proprietà anisotropiche, variano durante il processo di fratturazione costituendo una possibile causa della dispersione dei parametri di anisotropia stimati. Le inversioni dei tempi di arrivo delle onde SH forniscono elevati valori del parametro di anisotropia associato a questi segnali sismici. Tuttavia è importante sottolineare che si tratta di un’espressione della anisotropia effettiva del mezzo e non di quella intrinseca. Lo shear-wave splitting è considerato un robusto indicatore di anisotropia sismica. Nell’ambito di questo studio, questo fenomeno viene trattato in modo esaustivo, con particolare riguardo ai mezzi VTI. Il tempo di ritardo tra le due onde di taglio soggette a splitting può essere stimato dai dati sismici e quindi invertito per ottenere i parametri di anisotropia. La stima dei tempi di ritardo attraverso il metodo della cross-correlazione fornisce risultati consistenti per ricevitori vicini. L’inversione dei tempi di ritardo è basata sulle approssimazioni dei tempi di percorso delle onde SH ed SV in mezzi debolmente anisotropici e conferma l’anisotropia piuttosto pronunciata già messa in evidenza dalle analisi dei tempi di arrivo delle onde P ed SH. Sono state anche implementate tecniche di analisi dello shear-wave splitting più sofisticate, adatte a modelli di anisotropia più generali. Tuttavia, questi metodi già ampiamente utilizzati per l’analisi di eventi telesismici hanno fornito risultati poco affidabili, principalmente a causa del basso rapporto segnale-rumore caratterizzante i dati del giacimento di Abbott.
A material whose properties do not change with the direction along which they are measured is called isotropic. On the contrary, if the properties of the medium show directional dependency it is called anisotropic. Traditional seismic exploration is based on processing and interpretation of acoustic data and considers seismically isotropic subsoil. However, isotropy is always an approximate model to describe the geological formations, especially in sedimentary basins. Seismic imaging and estimation of subsurface velocities become inaccurate when anisotropic data are treated under the general assumption of isotropy. Consequently it is important to define the model and strength of anisotropy for the study area and use this information in data processing. The main goal of this study is the anisotropy characterization of the Abbott gas shale play located in the Arkoma basin, Oklahoma, USA. The data consist in seismic records obtained from two surface arrays of 1C geophones and 3C accelerometers, respectively, and acquired during the hydraulic fracturing of the reservoir. Surface (or near-surface) monitoring can be less expensive if compared to borehole monitoring when the observation wells must be drilled. The former technique is based on data acquisition from hundreds of receivers widely distributed over the Earth surface and gives a larger field view than borehole monitoring, generally limited to tenth of 3C receivers. Moreover, arrival time analyses of data recorded from surface widely-distributed receiver-networks are generally more robust than polarization studies carried out on borehole microseismic data. The drawback is a significant lower signal-to-noise ratio due to near surface heterogeneities. During the treatment of the Abbott gas shale, a few hundred microseismic events were recorded and the ten strongest events have been analyzed, together with the data from perforation shots. Vertical transverse isotropy (VTI) is, unarguably, the most common anisotropic model for sedimentary basins and particularly for shales. Seismic velocity in VTI media varies with direction of propagation away from the vertical, but not with azimuth. The analysis of the P-waves seismic dataset confirms VTI to be the best-suited model for the Abbott reservoir and/or overburden. P- and S-waves arrival times in homogeneous VTI media deviate from the hyperbolic moveout, which characterize seismic propagation in homogeneous isotropic media. The nonhyperbolicity of the traveltime can be used to estimate anisotropy parameters. The actual arrival times, picked from the experimental data, can be approximated considering analytic traveltime equations, which depend on such parameters. This inversion technique is tested with full wave synthetic data and applied to the Abbott dataset. The three Thomsen anisotropy parameters are estimated from P- and SH-arrival times of ten microseismic events, while only compressional waves are used for the inversion of four perforation shots. Moreover, the sensitivity of the P-wave arrival time inversion to picking noise and inaccuracies of input parameters is thoroughly analyzed. The inversions of the P-wave arrival times of the perforation shots give quite consistent anisotropy parameters, while the results from the compressional and shear waves arrival time inversions of the microseismic events are characterized by moderate scattering. This can be explained by the lower location accuracy and widespread distribution of the microseismic events, compared with the perforation shots. Moreover, the elastic properties of the sismogenic volume, as well as the local anisotropic properties, vary due to the process of fracturing and possibly cause the moderate scattering of the parameters inverted from the microseismic events. The inversions of the SH-wave arrival times result in consistently high values of the anisotropy parameter related to this wave mode. However, it is important to remark that this is the expression of effective and not intrinsic anisotropy. Shear-wave splitting is considered a robust indicator of seismic anisotropy. Such phenomenon is exhaustively addressed and described for VTI media, specifically. The time-delay between the two split waves can be estimated from the seismic records and inverted for anisotropy parameters. The estimation of the splitting times of a seismic event through the cross- correlation method gives consistent results for adjacent receivers. The inversion of the estimated time delays is based on SH- and SV-traveltimes approximations in weakly anisotropic media, and confirms the relatively high degree of anisotropy already highlighted by the P- and SH-wave arrival time analyses. More complex techniques of shear-wave splitting analysis, suitable for more general anisotropic models are also implemented. However, these methods, widely used for teleseismic shear-waves data, give unreliable results mainly because of the low signal-to-noise ratio characterizing the seismic data.
XXV Ciclo
1970

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.

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).

A study into potential gas shales is conducted to define the controlling factors of gas adsorption and evaluate gas adsorption capacity in shale gas reservoirs. The results from high-pressure adsorption experiment show that temperature, moisture and composition affect the gas adsorption in shale. In this study, a tool is introduced to predict gas adsorption capacity. This study helps to understand the mechanism of gas adsorption and evaluate gas storage in shale gas reservoirs.

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.

gh European energy demands, the difference in prices amongst Europe and ambitious gas producers, have produced a scenario of high competition in a region that suffers a lack of fossil resources still required for energy generation. Therefore, other sources are under the scope of various countries to mitigate these issues. Shale gas is one fuel that presents a scenario that would decrease European dependence on imported gas. Although shale gas production is unlikely to give the energy security desired to the whole Europe, it would make a difference for the communities that will adopt it. However, shale gas has acquired a bad reputation with the public, mainly because of its extraction methods. This bad reputation is attributed to hydraulic fracturing, technology well-known as fracking, and its risks associated towards air and water pollution. Therefore, companies, institutions and governments are looking for other alternative methods of extraction with more environmentally friendly processes. Producing extensive high-pressure pulse waves at the base of the wellbore by using detonation is a promising potential technique for shale gas extraction. A fundamental study of deflagration to detonation transition using recirculated shale gas formation with pure oxygen as an oxidiser has been studied to design a system with lower DDT distance and higher pressure waves. Three proposed cases of UK shale gas composition were studied. Chemical equilibrium software GASEQ and chemical kinetic software CHEMKIN-PRO were used to estimate the product parameters. Results showed that the effect produced by diluents, such as carbon dioxide, are eliminated by the use of higher hydrogen content carbon-to-hydrogen species for the three cases proposed. OpenFOAM CFD was used to calculate the deflagration to detonation transition parameters in stoichiometric hydrogen air mixtures to evaluate different obstacle geometries on the transition phenomenon to improve the detonation process. The shape and layout of obstacles were found to have a significant effect on flame acceleration, and subsequent detonation propagation. The interaction of transverse pressure waves generated at the obstructions governs the propagation mechanism. The transverse waves and its frequency appear to play a pivotal role in supporting the detonation wave. H iv It was found that rectangular shape obstacles reduce the reaction time, while triangular ones achieved detonation with the minimum run-up distance. On the other hand, semicircular shape obstacles generate the highest pressure in a detonation tube. The outcome from numerical calculations and CFD were the guide to construct an experimental rig of 21.2mm diameter and 1500mm length tube with different obstacle configurations to demonstrate the concept of pulse detonation for shale rock cracking. Experimental work has been performed to determine the potential of shale gas production in the Dullais Valley, South of Wales. It was found through several tests using BS standard volatile analyses, Transmission Electron Microscopy and pyrolysis RockEval evaluation that the potential of extraction in this region is fair, with similar concentrations of pyrite but with low energy content compared to those resources located in the Midlands and Yorkshire. However, the use of controlled pulse detonation could be the ideal technology for extraction in Wales, as low sulphur (S) content will produce lower unwanted emissions, with a process that can promote opening of pores and further gasification of oil based molecular, with a subsequent increase in shale gas production, topic that requires further research. Finally, a 2-dimensional simulation was performed using ANSYS Parameter Design Language (APDL) to investigate the effect of pressure pulse generated by the detonation tube on a pre-crack. Results showed that the layer close to the applied load will be displaced, which means that it will be smashed. The maximum Von Mises stresses were found to concentrate at the perforating hole corners, while the region immediately after the crack tip is susceptible to compression stresses. The Same behaviour was found for the stress intensity factor. According to that, it is believed that the cracks will propagate diagonally from the perforating hole base. Therefore, the current work has theoretically demonstrated the technology for shale gas recovery, with an optimised geometry consistent of internal obstacles, for a region with potential for shale gas exploitation.

Master of Science
Department of Chemical Engineering
James Edgar
In the past decade the technique of horizontal drilling and hydraulic fracturing has been improved so much that it has become a cost effective method to extract natural gas from shale formations deep below the earth’s surface. Natural gas extraction has boomed in the past few years in the United States, enough that it has driven prices to an all time low. The amount of natural gas reserves in the U.S. has led to claims that it can lead the country to energy independence. It has also been touted as a cleaner fuel for electricity generation and to power vehicles. This report explains hydraulic fracturing and horizontal drilling particularly with regards to utilizing the techniques for natural gas extraction from shale gas. It also discusses the environmental impact due to the drilling and gas extraction. It demonstrates that although the natural gas beneath the U.S. is a valuable resource, the impacts to the planet and mankind are not to be taken lightly. There is the potential for the effects to be long term and detrimental if measures are not taken now to control them. In addition although on the surface natural gas seems to be a greener fuel, particularly in comparison to gasoline, it is also considered worse for the environment.

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.

Shale gas development is transforming the energy landscape in the United States. Advances in production technologies, notably the dual application of horizontal drilling and hydraulic fracturing, allow the extraction of vast deposits of trapped natural gas that, until recently, were uneconomic to produce. The objective of this work is to develop mixed-integer programming models to support upstream operators in making faster and better decisions that ensure low-cost and responsible natural gas production from shale formations. We propose a multiperiod mixed-integer nonlinear programming (MINLP) model along with a tailored solution strategy for strategic, quality-sensitive shale gas development planning. The presented model coordinates planning and design decisions to maximize the net present value of a field-wide development project. By performing a lookback analysis based on data from a shale gas producer in the Appalachian Basin, we find that return-to-pad operations are the key to cost-effective shale gas development strategies. We address impaired water management challenges in active development areas through a multiperiod mixed-integer linear programming (MILP) model. This model is designed to schedule the sequence of fracturing jobs and coordinate impaired- and freshwater deliveries to minimize water management expenses, while simultaneously maximizing revenues from gas sales. Based on the results of a real-world case study, we conclude that rigorous optimization can support upstream operators in cost-effectively reducing freshwater consumption significantly, while also achieving effective impaired water disposal rates of less than one percent. We also propose a multiperiod MINLP model and a tailor-designed solution strategy for line pressure optimization in shale gas gathering systems. The presented model determines when prospective wells should be turned in-line, and how the pressure profile within a gathering network needs to be managed to maximize the net present value of a development project. We find that backoff effects associated with turn-in line operations can be mitigated through preventive line pressure manipulations. Finally, we develop deterministic and stochastic MILP models for refracturing planning. These models are designed to determine whether or not a shale well should be restimulated, and when exactly to refracture it. The stochastic refracturing planning model explicitly considers exogenous price forecast uncertainty and endogenous well performance uncertainty. Our results suggest that refracturing is a promising strategy for combatting the characteristically steep decline curves of shale gas wells.

Hydraulic fracturing operations utilized for shale gas production result in the generation of a large volume of flowback and produced water that contain suspended material, salts, hydrocarbons, metals, chemical additives, and naturally-occurring radioactive material. The water is impounded at drilling sites or treated off-site, resulting in significant generation of residual solids. These are either buried on site or are disposed in lined landfills. The objective of this study was to determine the levels of heavy metals and other elements of concern that will leach from these residual solids when placed in typical disposal environments. For this purpose, laboratory leaching experiments were employed wherein representative samples were brought into contact with a liquid to determine the constituents that would be leached by the liquid and potentially released into the environment. The samples used included sludge resulting from the physicochemical treatment of process water (TS), sludge solidified with cement kiln dust (SS), raw solids obtained by gravity separation of process water (RS), and drilling mud (DM). The samples were subjected to both single extraction (i.e. Shake Extraction Test, SET) and multiple extraction (i.e. Immersion Test, IT) leaching tests. For the shake extraction test, samples were mixed with a specific amount of leaching solution without renewal over a short time period. In the immersion test, samples were immersed in a specific amount of leaching solution that was periodically renewed over a longer period of time. For both these tests, analyses were performed on the filtered eluate. The tests were performed as per standards with modifications. Distilled de-ionized water, synthetic acid rain (pH ~ 4.2), weak acetic acid (pH ~ 2.88), and synthetic landfill leachate were used as leaching solutions to mimic specific disposal environments. Alkali metals (Li, K, Na), alkaline earth metals (Ba, Ca, Mg, Sr) and a halide (Br), which are typically associated with Marcellus shale and produced waters, leached at high concentrations from most of the residual solids sample. The SS sample, due to its stabilization with CKD, had a lower extraction efficiency as compared to the unconsolidated TS and RS samples. In EF 2.9 and EF SLL, the leaching took place under acidic conditions, while for EF DDI and EF 4.2, the leaching occurred in alkaline conditions. EF 2.9 and EF SLL were determined to be the most aggressive leaching solutions, causing the maximum solubility of most inorganic elements. Thus, high amounts of most EOCs may leach from these residual solids in MSW landfills disposed under co-disposal conditions. Agitation, pH and composition of the leaching solution were determined to be important variables in evaluating the leaching potential of a sample. The results of this study should help with the design of further research experiments being undertaken to develop environmentally responsible management/disposal strategies for these residual solids and also prove useful for regulatory authorities in their efforts to develop specific guidelines for the disposal of residuals from shale gas production operations.
Master of Science

Thesis (M. Eng.)--Massachusetts Institute of Technology, Dept. of Civil and Environmental Engineering, 2011.
Cataloged from PDF version of thesis.
Includes bibliographical references (p. 73-74).
With the dramatic increases in crude oil prices there has been a need to find reliable energy substitutions. One substitution that has been used in the United States is natural gas. However, with the increased use of natural gas, conventional sources are being depleted rapidly. Due to the strong use of conventional gas sources people have turned to unconventional gas sources. Unconventional gas sources are deemed economically infeasible to produce at the current price of natural gas. The reason some sources are unconventional is because the formation that holds the natural gas is highly impermeable, eg shale. Sources of unconventional natural gas in the United States are found in shales across the country; the Marcellus shale is one of these sources. The Marcellus shale is the largest natural gas source in the United States and is quickly becoming a major gas play. Estimates show that there are trillions of cubic feet of natural gas stored within the Marcellus shale, and energy companies are flocking to the area to extract it. This paper will discuss the techniques used by operators to extract natural gas in the Marcellus Shale. The focus will be on the drilling and hydraulic fracturing processes. A discussion regarding the environmental concerns when extracting natural gas follows. It was found that the methods used to extract natural gas, while effective, can harm the areas water supply. New technologies are being developed that use less water, are safer for the environment, and just as effective as the older methods in most situations.
by Zachary Boswell.
M.Eng.

Thesis: Ph. D., Massachusetts Institute of Technology, Department of Chemical Engineering, 2017.
Cataloged from PDF version of thesis.
Includes bibliographical references (pages 259-274).
This thesis addresses the challenges brought forth by the shale oil and gas revolution through the application of formal optimization techniques. Two frameworks, each addressing the monetization of shale oil and gas resources at different ends of the scale spectrum, are developed. Importantly, these frameworks accounted for both the dynamic and stochastic aspects of the problem at hand. The first framework involves the development of a strategy to allocate small-scale mobile plants to monetize associated or stranded gas. The framework is applied to a case study in the Bakken shale play where large quantities of associated gas are flared. Optimal strategies involving the continuous redeployment of plants are analyzed in detail. The value of the stochastic solution with regards to uncertainty in resource availability is determined and it indicates that mobile plants possess a high degree of flexibility to handle uncertainty. The second framework is a comprehensive supply chain optimization model to determine optimal shale oil and gas infrastructure investments in the United States. Assuming two different scenario sets over a time horizon of twenty-five years, the features of the optimal infrastructure investments and associated operating decisions are determined. The importance of incorporating uncertainty into the framework is demonstrated and the relationship between the stability of the stochastic solution and the variance of the distribution of future parameters is analyzed. The thesis also analyzes the Continuous Flow Stirred Tank Reactor (CFSTR) equivalence principle as a method for screening and targeting favorable reaction pathways, with applications directed towards gas-to-liquids conversion. The principle is found to have limited usefulness when applied to series reactions due to an unphysical independence of the variables which allows for the maximization of production of any intermediate species regardless of the magnitude of its rate of depletion. A reformulation which eliminates the unphysical independence is proposed. However, the issue of arbitrary truncation of downstream reactions remains.
by Siah Hong Tan.
Ph. D.

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.

Shale gas has emerged as a potential resource to transform the global energy market. Nevertheless, gas extraction from tight shale formations is only possible after horizontal drilling and hydraulic fracturing, which generally demand large amounts of water. Part of the ejected fracturing fluid returns to the surface as flowback water, containing a variety of pollutants. Thus, water reuse and water recycling technologies have received further interest for enhancing overall shale gas process efficiency and sustainability. Thereby, the objectives of this thesis are: - Develop mathematical models to treat flowback and produced water at various salinities and flow rates, decreasing the high environmental impact due to the freshwater withdrawal and wastewater generated during shale gas production at minimum cost. - Develop mathematical programming models for planning shale gas water management through the first stage of the well's life to promote the reuse of flowback water by optimizing simultaneously all operations belonging several wellpads. Within the first objective, we developed medium size generalized disjunctive-programming (GDP) models reformulated as mixed integer non-linear programming problems (MINLPs). First, we focused on flowback water pretreatment and later, in wastewater desalination treatment. Particularly, an emergent desalination technology, Membrane Distillation, has been studied. All mathematical models have been implemented using GAMS® software. First, we introduce a new optimization model for wastewater from shale gas production including a superstructure with several water pretreatment alternatives. The mathematical model is formulated via GDP to minimize the total annualized cost. Hence, the superstructure developed allows identifying the optimal pretreatment sequence with minimum cost, according to inlet water composition and wastewater desired destination (i.e., water reuse as fracking fluid or desalination in thermal or membrane techonologies). As each destination requires specific composition constraints, three case studies illustrate the applicability of the proposed approach. Additionally, four distinct flowback water compositions are evaluated for the different target conditions. The results highlight the ability of the developed model for the cost-effective water pretreatment system synthesis, by reaching the required water compositions for each specified destination. Regarding desalination technologies, a rigorous optimization model with energy recovery for the synthesis of multistage direct contact membrane distillation (DCMD) system has been developed. The mathematical model is focused on maximizing the total amount of water recovered. The outflow brine is fixed close to salt saturation conditions (300 g·kg-1) approaching zero liquid discharge (ZLD). A sensitivity analysis is performed to evaluate the system’s behavior under different uncertainty sources such as the heat source availability and inlet salinity conditions. The results emphasize the applicability of this promising technology, especially with low steam cost or waste heat, and reveal variable costs and system configurations depending on inlet conditions. Within the second objective, large-scale multi-period water management problems, and collaborative water management models have been studied. Thus, to address water planning decisions in shale gas operations, in a first stage a new non-convex MINLP optimization model is presented that explicitly takes into account the effect of high concentration of total dissolved solids (TDS) and its temporal variations in the impaired water. The model comprises different water management strategies: direct reuse, treatment or send to Class II disposal wells. The objective is to maximize the “sustainability profit” to find a compromise solution among the three pillars of sustainability: economic, environmental and social criteria. The solution determines freshwater consumption, flowback destination, the fracturing schedule, fracturing fluid composition and the number of tanks leased at each time period. Because of the rigorous determination of TDS in all water streams, the model is a nonconvex MINLP model that is tackled in two steps: first, an MILP model is solved on the basis of McCormick relaxations for the bilinear terms; next, the binary variables that determine the fracturing schedule are fixed, and a smaller MINLP is solved. Finally, several case studies based on Marcellus Shale Play are optimized to illustrate the effectiveness of the proposed formulation. Later, a simplified version of the shale gas water management model developed in the previous work has been used to study possible cooperative strategies among companies. This model allows increasing benefits and reduces costs and environmental impacts of water management in shale gas production. If different companies are working in the same shale zone and their shale pads are relatively close (under 50 km), they might adopt a cooperative strategy, which can offer economic and environmental advantages. The objective is to compute a distribution of whatever quantifiable unit among the stakeholders to achieve a stable agreement on cooperation among them. To allocate the cost, profit and/or environmental impact among stakeholders, the Core and Shapley value are applied. Finally, the impact of cooperation among companies is shown by two examples involving three and eight players, respectively. The results show that adopting cooperative strategies in shale water management, companies are allowed to improve their benefits and to enhance the sustainability of their operations. The results obtained in this thesis should help to make cost-effective and environmentally-friendly water management decisions in the eventual development of shale gas wells.

The complex interplay between the physical and flow properties of shales was investigated. A methodology was developed to estimate free and bound porosity fractions from NMR-T2 experiments on shales, while a second order flow model was proposed to interpret gas permeability data. Slippage effects appeared to be influenced by characteristic pore lengths, while poroelastic behaviour was linked to compositional data. Potential associations emerged between FFI/BVI, pore sizes, fluid dynamic phenomena, and shale composition.

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.

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.

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.

This research assesses the impacts of developing shale gas in the UK, with the focus of determining whether or not it is possible to develop it sustainably and how it could affect the electricity and gas mix. There is much uncertainty on the impacts of developing shale gas in the UK, as the country is currently in the early stages of exploration drilling and the majority of studies which have been carried out to analyse the effects of shale gas development have been US specific. To address these questions, the environmental, economic and social sustainability have been assessed and the results integrated to evaluate the overall sustainability. The impacts of shale gas electricity have been assessed so that it can be compared with other electricity generation technologies (coal, nuclear, renewables etc.), to ascertain its impacts on the UK electricity mix. Life cycle assessment is used to evaluate the environmental sustainability of shale gas electricity (and other options), while life cycle costing and social sustainability assessment have been used to evaluate the economic and social sustainability. Multi-criteria decision analysis has been used to combine the results of three to evaluate the overall sustainability. The incorporation of shale gas into the UK electricity mix is modelled in two future scenarios for the year 2030. The scenarios compare different levels of shale gas penetration: low and high. The results show that shale gas will have little effect on improving the environmental sustainability and energy security of the UK’s electricity mix, but could help ease energy prices. In comparison with other options, shale gas is not a sustainable option, as it has higher environmental impacts than the non-fossil fuels and conventional gas and liquefied natural gas: 460 g CO2-Eq. is emitted from the shale gas electricity life cycle, while conventional gas emits 420 g CO2-Eq. and wind 12 g CO2-Eq. The power plant and drilling fluid are the main impact hot spots in the life cycle, while hydraulic fracturing contributes a small amount (5%). In addition to this, there are a number of social barriers which need to be addressed, notably: traffic volume and congestion could increase by up to 31%, public support is low and wastewater produced from hydraulic fracturing could put strain on wastewater treatment facilities. However, the results indicate that shale gas is economically viable, as the cost of electricity is cheaper than solar photovoltaic, biomass and hydroelectricity (9.59 p/kWh vs 16.90, 11.90 and 14.40 p/kWh, respectively). The results of this thesis show that there is a trade-off in the impacts, but because of its poor environmental and social ratings shale gas is not the best option for UK electricity. The results also identify areas for improvement which should be targeted, as well as policy recommendations for best practice and regulation if shale gas were to be developed in the UK.

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.

This thesis explores the factors influencing governmental policy preferences on the uncertain issue of shale gas development. I argue that there is no convincing expected utility of shale gas development, and that, in light of conflicting evidence, governmental decision-makers cannot believe it to be so. The notion of a ‘rational actor’ government deciding on shale gas based on its utility offers limited explanatory value. I am telling a more comprehensive story of shale gas and by using different clues taken from political economy and behavioural economics theory, develop several narratives about respective dimensions of the decision-making process: a rational expected utility analysis, a perspective on the influence of private interest groups, and a narrative on capture through ideational repertoire and cognitive biases. To this end classical literature of decision-making under risk and uncertainty is reviewed and political economy theory is brought in to widen the debate. The key arguments of this study are that policy decisions on shale gas are irrational from a classical political science perspective; that economic claims made about policy decisions are defying economic logic; that strong interest groups are distorting a market-based energy policy; and that pre-existing ideas about the energy system unduly influence the decision process regardless of their actual applicability. I suggest that fracking is simply so compatible with the current repertoire of ideas, practices and tools around energy policy, that engaging in it becomes a logical conclusion, whereas not to engage in it would require a paradigmatic change. These arguments are taken forward by an in-depth analysis of the decision-making around shale gas made by the United States government and the United Kingdom government since the commercial development of shale gas became possible through technological innovation in the 21st century. The thesis serves to shine light on the story of shale gas policy, but also to explore separate dimensions of policy-making under uncertainty in which cognitive and parochial factors prove more influential than so-called rational calculations.

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.

Economic benefits of shale gas production in addition to its potential for enabling energy security are driving the strategic development of unconventional natural gas in the U.S. However, shale gas production poses potential detrimental impacts on the surrounding ecosystems. In particular, sustainable management of high salinity wastewater is one of the critical challenges facing shale gas industry. While recycling shale gas wastewater is a practical short-term solution to minimize total water use in the fracturing process it may not be a viable strategy from a long-term management perspective. Moreover, direct disposal into Salt Water Disposal (SWD) wells which is the most common management strategy in the U.S. is not cost effective in Marcellus shale play due to limited disposal capacity.

This work develops a systems-level optimization framework for guiding economically conscious management of high salinity wastewater in Marcellus shale play in Pennsylvania (PA) with a focus on using membrane distillation (MD) as the treatment technology. Detailed technoeconomic assessment (TEA) is performed to assess the economic feasibility of MD for treatment of shale gas wastewater with and without availability of waste heat. Natural gas compressor stations (NG CS) are chosen as potential sources of waste heat and rigorous thermodynamic models are developed to quantify the waste heat recovery opportunities from NG CS. The information from waste heat estimation and TEA are then utilized in the optimization framework for investigating the optimal management of shale gas wastewater. Wastewater management alternatives ranging from direct disposal into SWD wells to advanced centralized, decentralized, and onsite treatment options using MD are included in the optimization model.

The optimization framework is applied to four case studies in Greene and Washington counties in southwest and Susquehanna and Bradford counties in Northeast PA where major shale gas development activities take place. The results of this analysis reveal that onsite treatment of wastewater at shale gas extraction sites in addition to treating wastewater at NG CS where available waste heat could be utilized to offset the energy requirements of treatment process are the most economically promising management options that result in major economic benefit over direct disposal into SWD.

The Early Permian Carynginia Formation and the Late Triassic Kockatea Shale are prospective shale gas resources in the Perth Basin. Various geological studies such as visual core description and petrography were conducted to understand about the lithofacies and depositional environments in the target formations. Key geochemical parameters such as TOC, thermal maturity and RHP were identified through rock-eval pyrolysis. Petrophysical studies were applied in detecting organic richness and fracability of the under-study shale plays.

Given their potential applications for a number of engineering purposes, the geomechanics of shale reservoirs is becoming one of the most important issues in modern geomechanics. Borehole stability modeling, geophysics, shale oil and shale gas reservoirs, and underground storage of CO2 and nuclear waste are some of these potential applications to name a few. The growing interest in these reservoirs, as a source for hydrocarbons production, has resulted in an increasing demand for fundamental material property data. Laboratory analysis and constitutive models have shown that rock elastic and deformational properties are not single-value, well-defined parameters for a given rock. Finding suitable values for these parameters is of vital importance in many geomechanical applications. In this thesis an extensive experimental program to explore geomechanical properties of shale was developed. A series of triaxial tests were performed in order to evaluate the elasticity, yielding, and failure response of Marcellus shale specimens as a function of pressure, temperature, and bedding angle. Additional characterization includes mineralogy, porosity, and fabric. Rock samples used in this study came from three different locations and depths: one actual reservoir (~7,500 ft. deep), and two outcrops (~300 ft. and ~0 ft. deep).

Thesis: S.M. in Technology and Policy, Massachusetts Institute of Technology, Engineering Systems Division, Technology and Policy Program, 2015.
Cataloged from PDF version of thesis.
Includes bibliographical references (pages 137-147).
Shale gas and tight oil are energy resources of growing importance to the U.S. and the world. The combination of horizontal drilling and hydraulic fracturing has enabled economically feasible production from these resources, leading to a surge in domestic oil and gas production. This is providing an economic boon and reducing reliance on foreign sources of energy in the U.S., but there are still a number of environmental, economic, and technical challenges that must be overcome to unlock the resource's full potential. One key challenge is understanding variability in individual well performance-in terms of both drilling time (a key driver of well cost) and well productivity-which has led to greater than anticipated economic risk associated with shale gas and tight oil development. Thus far, more reliable forecasting has remained elusive due to its prohibitive cost and the poorly understood nature of the resource. There is an opportunity to make use of available drilling and production data to improve the characterization of variability. For my analysis, I use publicly-available well production data and drilling reports from a development campaign. In order to characterize variability, I use a combination of graphical, statistical, and data analytics methods. For well productivity, I use probability plots to demonstrate a universality to the distribution shape, which can accurately be described as lognormal. Building on this distributional assumption, I demonstrate the utility of Bayesian statistical inference for improving estimates of the distribution parameters, which will allow companies to better anticipate resource variability and make better decisions under this uncertainty. For drilling, I characterize variability in operations by using approximate string matching to compare drilling activity sequences, leading to a metric for operational variability. Activity sequences become more similar over time, consistent with the notion of standardization. Finally, I investigate variability of drilling times as they progress along the learning curve, using probability plots again. I find some indication of lognormality, with implications for how learning in drilling should be measured and predicted. This thesis emphasizes the relevance of data analytics to characterizing performance variability across the spectrum in shale gas and tight oil. The findings also demonstrate the value of such an approach for identifying patterns of behavior, estimating future variability, and guiding development strategies.
by Justin B. Montgomery.
S.M. in Technology and Policy