In 2007, the Barnett Shale in the Fort Worth basin of Texas produced 1.1 trillion cubic feet (Tcf) gas and ranked second in U.S gas production. Despite its importance, controls on Barnett Shale gas well performance are poorly understood. Regional and vertical variations of reservoir properties and their effects on well performances have not been assessed. Therefore, we conducted a study of Barnett Shale stratigraphy, petrophysics, and production, and we integrated these results to clarify the controls on well performance. Barnett Shale ranges from 50 to 1,100 ft thick; we divided the formation into 4 reservoir units that are significant to engineering decisions. All but Reservoir Unit 1 (the lower reservoir unit) are commonly perforated in gas wells. Reservoir Unit 1 appears to be clay-rich shale and ranges from 10 to 80 ft thick. Reservoir Unit 2 is laminated, siliceous mudstone and marly carbonate zone, 20 to 300 ft thick. Reservoir Unit 3 is composed of multiple, stacked, thin (~15-30 ft thick), upward coarsening sequences of brittle carbonate and siliceous units interbedded with ductile shales; thickness ranges from 0 to 500 ft. Reservoir Unit 4, the upper Barnett Shale is composed dominantly of shale interbedded with upward coarsening, laterally persistent, brittle/ductile sequences ranging from 0 to 100 ft thick. Gas production rates vary directly with Barnett Shale thermal maturity and structural setting. For the following five production regions that encompass most of the producing wells, Peak Monthly gas production from horizontal wells decreases as follows: Tier 1 (median production 60 MMcf) to Core Area to Parker County to Tier 2 West to Oil Zone-Montague County (median production 10 MMcf). The Peak Monthly oil production from horizontal wells is in the inverse order of gas production; median Peak Monthly oil production is 3,000 bbl in the Oil Zone-Montague County and zero in Tier 1. Generally, horizontal wells produce approximately twice as much oil and gas as vertical wells.This research clarifies regional variations of reservoir and geologic properties of the Barnett Shale. Result of these studies should assist operators with optimization of development strategies and gas recovery from the Barnett Shale.

In 2007, the Barnett Shale in the Fort Worth basin of Texas produced 1.1 trillion cubic feet (Tcf) gas and ranked second in U.S gas production. Despite its importance, controls on Barnett Shale gas well performance are poorly understood. Regional and vertical variations of reservoir properties and their effects on well performances have not been assessed. Therefore, we conducted a study of Barnett Shale stratigraphy, petrophysics, and production, and we integrated these results to clarify the controls on well performance. Barnett Shale ranges from 50 to 1,100 ft thick; we divided the formation into 4 reservoir units that are significant to engineering decisions. All but Reservoir Unit 1 (the lower reservoir unit) are commonly perforated in gas wells. Reservoir Unit 1 appears to be clay-rich shale and ranges from 10 to 80 ft thick. Reservoir Unit 2 is laminated, siliceous mudstone and marly carbonate zone, 20 to 300 ft thick. Reservoir Unit 3 is composed of multiple, stacked, thin (~15-30 ft thick), upward coarsening sequences of brittle carbonate and siliceous units interbedded with ductile shales; thickness ranges from 0 to 500 ft. Reservoir Unit 4, the upper Barnett Shale is composed dominantly of shale interbedded with upward coarsening, laterally persistent, brittle/ductile sequences ranging from 0 to 100 ft thick. Gas production rates vary directly with Barnett Shale thermal maturity and structural setting. For the following five production regions that encompass most of the producing wells, Peak Monthly gas production from horizontal wells decreases as follows: Tier 1 (median production 60 MMcf) to Core Area to Parker County to Tier 2 West to Oil Zone-Montague County (median production 10 MMcf). The Peak Monthly oil production from horizontal wells is in the inverse order of gas production; median Peak Monthly oil production is 3,000 bbl in the Oil Zone-Montague County and zero in Tier 1. Generally, horizontal wells produce approximately twice as much oil and gas as vertical wells.This research clarifies regional variations of reservoir and geologic properties of the Barnett Shale. Result of these studies should assist operators with optimization of development strategies and gas recovery from the Barnett Shale.

All the oil and gas wells producing in the Arikaree Creek Field, Colorado targeted the Spergen Formation along similar structures within a wrench fault system; however, the wells have vastly different production values. This thesis develops a predictive model for high production in the field while also accounting for a failed waterflood event that was initiated in 2016. Petrophysical analysis of thirteen wells show that high producing wells share common characteristics of pay zone location, lithology, porosity and permeability with one another and that the Spergen Formation is not homogenous. Highly productive wells have pay zones in the lower part of the formation in sections that are dolomitized, and have anonymously high water saturation. This is likely related to the paragenesis of the formation that dolomitized the lower parts of the formation, increasing porosity and permeability, but leaving the pay zones with the high water saturation values. This heterogeneity likely accounts for the failed waterflood. Results show that the important petrophysical components for highly productive wells are the location of the payzone within the reservoir, porosity, permeability and water saturation. Additionally, homogeneity is crucial for successful waterflooding, which was not present.

The SACROC unit is an isolated carbonate platform style of reservoir that typifies a peak icehouse system. Icehouse carbonate platforms are one of the least well understood and documented carbonate reservoir styles due to the reservoir heterogeneities they embody. The current study is an attempt to recognize carbonate rock types defined based on rock fabrics by integrating log and core based petrophysical analysis in high-frequency cycle (HFC) scale sequence stratigraphic framework and to improve our ability to understand static and dynamic petrophysical properties of these reservoir rock types, and there by, improve our understanding of heterogeneity in the middle early to late early Canyon (Canyon 2) high frequency sequence (HFS) in the Northern Platform of the SACROC Unit. Based on core descriptions, four different sub-tidal depositional facies were defined in the Canyon 2 HFS. Identified depositional facies were grouped into three different reservoir rock types in respect to their rock fabrics in order for the HFC scale petrophysical reservoir rock type characteristic analysis. Composed of succession of the identified reservoir rocks, twenty different HFCs were determined within the HFC scale sequence stratigraphic framework. The overall trend in the HFCs demonstrate systematic coarsening upward cycles with high reservoir quality at the cycle tops and low reservoir quality at the cycle bottoms. It was observed in terms of systems tracts described within the cycle scale frame work that the overall stacking pattern for high stand systems tracts (HST) and transgressive systems tracts (TST) is aggradational. And, the reservoir rocks representing the HST are more porous and permeable than those of TST. In addition to that, it was detected that the diagenetic overprint on the HST reservoir rocks is more than that of the TST. According to the overall petrophysical observations, the grain-dominated packstone deposited during HST was interpreted as the best reservoir rock. Upon well log analysis on the identified reservoir rocks, some specific log responses were attributed to the identified reservoir rocks as their characteristic log signatures. / text

3 ABSTRACT The work is focused on analysis of five structural well profiles penetrating sediments of the Bohemian Cretaceous Basin and the underlying Upper Palaeozoic continental basins to the crystalline basement. The objectives of well profile analysis are sedimentary formation evaluation from well log analysis and statistical analysis and evaluation of some physical properties of sedimentary rocks, which have been determined by measurements of drill cores. The aim of the work is to verify the possibility of porosity evaluation from well log analysis in the Bohemian Cretaceous Basin and the underlying Upper Palaeozoic continental basins. The next aim is to compare different geological environments with respect to physical properties of rocks. The content of the work involves presentation of well log curves, computation of porosity values and comparison between the resulting values of porosity from resistivity log, acoustic log and neutron-neutron log and from laboratory measurements of drill core samples. Data from five deep structural wells are used. Different geological environments were compared by statistical methods with respect to physical properties of rocks measured on well core samples from these five wells. Porosity evaluation from well log analysis is difficult but it is possible provided that...

In sedimentary basins, rock thermal conductivity can vary both laterally and vertically, thus altering the basin’s thermal structure locally and regionally. Knowledge of the thermal conductivity of geological formations and its spatial variations is essential, not only for quantifying basin evolution and hydrocarbon maturation processes, but also for understanding geothermal conditions in a geological setting. In conjunction with the temperature gradient, thermal conductivity represents the basic input parameter for the determination of the heat-flow density; which, in turn, is applied as a major input parameter in thermal modeling at different scales. Drill-core samples, which are necessary to determine thermal properties by laboratory measurements, are rarely available and often limited to previously explored reservoir formations. Thus, thermal conductivities of Mesozoic rocks in the North German Basin (NGB) are largely unknown. In contrast, geophysical borehole measurements are often available for the entire drilled sequence. Therefore, prediction equations to determine thermal conductivity based on well-log data are desirable. In this study rock thermal conductivity was investigated on different scales by (1) providing thermal-conductivity measurements on Mesozoic rocks, (2) evaluating and improving commonly applied mixing models which were used to estimate matrix and pore-filled rock thermal conductivities, and (3) developing new well-log based equations to predict thermal conductivity in boreholes without core control. Laboratory measurements are performed on sedimentary rock of major geothermal reservoirs in the Northeast German Basin (NEGB) (Aalenian, Rhaethian-Liassic, Stuttgart Fm., and Middle Buntsandstein). Samples are obtained from eight deep geothermal wells that approach depths of up to 2,500 m. Bulk thermal conductivities of Mesozoic sandstones range between 2.1 and 3.9 W/(m∙K), while matrix thermal conductivity ranges between 3.4 and 7.4 W/(m∙K). Local heat flow for the Stralsund location averages 76 mW/m², which is in good agreement to values reported previously for the NEGB. For the first time, in-situ bulk thermal conductivity is indirectly calculated for entire borehole profiles in the NEGB using the determined surface heat flow and measured temperature data. Average bulk thermal conductivity, derived for geological formations within the Mesozoic section, ranges between 1.5 and 3.1 W/(m∙K). The measurement of both dry- and water-saturated thermal conductivities allow further evaluation of different two-component mixing models which are often applied in geothermal calculations (e.g., arithmetic mean, geometric mean, harmonic mean, Hashin-Shtrikman mean, and effective-medium theory mean). It is found that the geometric-mean model shows the best correlation between calculated and measured bulk thermal conductivity. However, by applying new model-dependent correction, equations the quality of fit could be significantly improved and the error diffusion of each model reduced. The ‘corrected’ geometric mean provides the most satisfying results and constitutes a universally applicable model for sedimentary rocks. Furthermore, lithotype-specific and model-independent conversion equations are developed permitting a calculation of water-saturated thermal conductivity from dry-measured thermal conductivity and porosity within an error range of 5 to 10%. The limited availability of core samples and the expensive core-based laboratory measurements make it worthwhile to use petrophysical well logs to determine thermal conductivity for sedimentary rocks. The approach followed in this study is based on the detailed analyses of the relationships between thermal conductivity of rock-forming minerals, which are most abundant in sedimentary rocks, and the properties measured by standard logging tools. By using multivariate statistics separately for clastic, carbonate and evaporite rocks, the findings from these analyses allow the development of prediction equations from large artificial data sets that predict matrix thermal conductivity within an error of 4 to 11%. These equations are validated successfully on a comprehensive subsurface data set from the NGB. In comparison to the application of earlier published approaches formation-dependent developed for certain areas, the new developed equations show a significant error reduction of up to 50%. These results are used to infer rock thermal conductivity for entire borehole profiles. By inversion of corrected in-situ thermal-conductivity profiles, temperature profiles are calculated and compared to measured high-precision temperature logs. The resulting uncertainty in temperature prediction averages < 5%, which reveals the excellent temperature prediction capabilities using the presented approach. In conclusion, data and methods are provided to achieve a much more detailed parameterization of thermal models. / Die thermische Modellierung des geologischen Untergrundes ist ein wichtiges Werkzeug bei der Erkundung und Bewertung tiefliegender Ressourcen sedimentärer Becken (e.g., Kohlenwasserstoffe, Wärme). Die laterale und vertikale Temperaturverteilung im Untergrund wird, neben der Wärmestromdichte und der radiogenen Wärmeproduktion, hauptsächlich durch die Wärmeleitfähigkeit (WLF) der abgelagerten Gesteinsschichten bestimmt. Diese Parameter stellen die wesentlichen Eingangsgrößen für thermische Modelle dar. Die vorliegende Dissertation befasst sich mit der Bestimmung der Gesteins-WLF auf verschiedenen Skalen. Dies umfasst (1) laborative WLF-Messungen an mesozoischen Bohrkernproben, (2) die Evaluierung und Verbesserung der Prognosefähigkeit von Mischgesetzten zur Berechnung von Matrix- und Gesamt-WLF sedimentärer Gesteine, sowie (3) die Entwicklung neuer Prognosegleichungen unter Nutzung bohrlochgeophysikalischer Messungen und multivariater Analysemethoden im NGB. Im Nordostdeutschen Becken (NEGB) wurden für die wichtigsten geothermischen Reservoire des Mesozoikums (Aalen, Rhät-Lias-Komplex, Stuttgart Formation, Mittlerer Buntsandstein) Bohrkerne geothermischer Tiefbohrungen (bis 2.500 m Tiefe) auf Ihre thermischen und petrophysikalischen Eigenschaften hin untersucht. Die WLF mesozoischer Sandsteine schwankt im Mittel zwischen 2,1 und 3,9 W/(m∙K), die WLF der Gesteinsmatrix hingegen im Mittel zwischen 3,4 und 7,4 W/(m∙K). Neu berechnete Werte zur Oberflächenwärmestromdichte (e.g., 76 mW/m², Stralsund) stehen im Einklang mit den Ergebnissen früherer Studien im NEGB. Erstmals im NDB wurde für das mesozoisch/känozoischen Intervall am Standort Stralsund ein in-situ WLF-Profil berechnet. In-situ Formations-WLF, für als potentielle Modelschichten interessante, stratigraphische Intervalle, variieren im Mittel zwischen 1,5 und 3,1 W/(m∙K) und bilden eine gute Grundlage für kleinskalige (lokale) thermische Modelle. Auf Grund der in aller Regel nur eingeschränkt verfügbaren Bohrkernproben sowie des hohen laborativen Aufwandes zur Bestimmung der WLF waren alternative Methoden gesucht. Die Auswertung petrophysikalischer Bohrlochmessungen mittels mathematischer-statistischer Methoden stellt einen lang genutzten und erprobten Ansatz dar, welcher in seiner Anwendbarkeit jedoch auf die aufgeschlossenen Gesteinsbereiche (Genese, Geologie, Stratigraphie, etc.) beschränkt ist. Daher wurde ein leicht modifizierter Ansatz entwickelt. Die thermophysikalischen Eigenschaften der 15 wichtigsten gesteinsbildenden Minerale (in Sedimentgesteinen) wurden statistisch analysiert und aus variablen Mischungen dieser Basisminerale ein umfangreicher, synthetischer Datensatz generiert. Dieser wurde mittels multivariater Statistik bearbeitet, in dessen Ergebnis Regressionsgleichungen zur Prognose der Matrix-WLF für drei Gesteinsgruppen (klastisch, karbonatisch, evaporitisch) abgeleitet wurden. In einem zweiten Schritt wurden für ein Echtdatenset (laborativ gemessene WLF und Standardbohrlochmessungen) empirische Prognosegleichungen für die Berechnung der Gesamt-WLF entwickelt. Die berechneten WLF zeigen im Vergleich zu gemessenen WLF Fehler zwischen 5% und 11%. Die Anwendung neu entwickelter, sowie in der Literatur publizierter Verfahren auf den NGB-Datensatz zeigt, dass mit den neu aufgestellten Gleichungen stets der geringste Prognosefehler erreicht wird. Die Inversion neu berechneter WLF-Profile erlaubt die Ableitung synthetischer Temperaturprofile, deren Vergleich zu gemessenen Gesteinstemperaturen in einen mittleren Fehler von < 5% resultiert. Im Rahmen geothermischer Berechnungen werden zur Umrechnung zwischen Matrix- und Gesamt-WLF häufig Zwei-Komponenten-Mischmodelle genutzt (Arithmetisches Mittel, Harmonische Mittel, Geometrisches Mittel, Hashin-Shtrikman Mittel, Effektives-Medium Mittel). Ein umfangreicher Datensatz aus trocken- und gesättigt-gemessenen WLF und Porosität erlaubt die Evaluierung dieser Modelle hinsichtlich Ihrer Prognosefähigkeit. Diese variiert für die untersuchten Modelle stark (Fehler: 5 – 53%), wobei das geometrische Mittel die größte, quantitativ aber weiterhin unbefriedigende Übereinstimmungen zeigt. Die Entwicklung und Anwendung mischmodelspezifischer Korrekturgleichungen führt zu deutlich reduzierten Fehlern. Das korrigierte geometrische Mittel zeigt dabei, bei deutlich reduzierter Fehlerstreubreite, erneut die größte Übereinstimmung zwischen berechneten und gemessenen Werten und scheint ein universell anwendbares Mischmodel für sedimentäre Gesteine zu sein. Die Entwicklung modelunabhängiger, gesteinstypbezogener Konvertierungsgleichungen ermöglicht die Abschätzung der wassergesättigten Gesamt-WLF aus trocken-gemessener WLF und Porosität mit einem mittleren Fehler < 9%. Die präsentierten Daten und die neu entwickelten Methoden erlauben künftig eine detailliertere und präzisere Parametrisierung thermischer Modelle sedimentärer Becken.

The recent and rapid growth of horizontal drilling in the Anadarko basin necessitates newer studies to characterize reservoir and source rock quality in the region. Most oil production in the basin comes from the Granite Wash reservoirs, which are composed of stacked tight sandstones and conglomerates that range from Virgillian (305-299 Ma) to Atokan (311-309.4 Ma) in age. By utilizing geophysical well logging data available in raster format, the Granite Wash reservoirs and their respective marine flooding surfaces were stratigraphically mapped across the regional fault systems. Additionally, well log trends were calibrated with coincident core data to minimize uncertainty regarding facies variability and lateral continuity of these intervals. In this thesis, inferred lithofacies were grouped into medium submarine fan lobe, distal fan lobe, and offshore facies (the interpreted depositional environments). By creating isopach and net sand maps in Petra, faulting in the Missourian was determined to have occurred syndepositionally at the fifth order scale of stratigraphic hierarchy.