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Explorer Article

Drones and other automata will be more commonplace in the oil field of tomorrow, but they have some obstacles to clear first.

American Association of Petroleum Geologists (AAPG)
Explorer Article

The oil and gas industry is facing a tidal wave of retirements as the Great Crew Change occurs, but the challenges of replacing technical professionals might not be as difficult as you think. On the other hand, they might be considerably worse.

American Association of Petroleum Geologists (AAPG)
Spheres of Influence Article

Reliable access to safe, clean drinking water is something most people in the United States take for granted. We turn on our tap and out comes clean water! We brush our teeth, wash our clothes, cook our meals and bathe our children. In the United States, it’s abundant, reliable and relatively cheap. Even kings of the past didn’t have such luxury.

American Association of Petroleum Geologists (AAPG)
Spheres of Influence Article

Environmental issues are a worldwide concern - the Division of Environmental Geosciences has an obligation to provide science-based opinions of these issues to educate the public, government officials and other petroleum industry professionals.

American Association of Petroleum Geologists (AAPG)
Search and Discovery Article

Subsurface electromagnetic (EM) measurements, namely galvanic resistivity, EM induction, EM propagation, and dielectric dispersion, exhibit frequency dependence due to the interfacial polarization (IP) of clay minerals, clay-sized particles, and conductive minerals. Existing oil-in-place estimation methods based on subsurface EM measurements do not account for dielectric permittivity, dielectric dispersion, and dielectric permittivity anisotropy arising from the IP effects. The conventional interpretation methods generate inaccurate oil-in-place estimates in clay- and pyrite-bearing shales because they separately interpret the multi-frequency effective conductivity and permittivity using empirical models.  We introduce a new inversion-based method for accurate oil-in-place estimation in clay- and pyrite-bearing shales. The inversion algorithm is coupled with an electrochemical model that accounts for the frequency dispersion in effective conductivity and permittivity due to the above-mentioned IP effects. The proposed method jointly processes the multi-frequency effective conductivity and permittivity values computed from the subsurface EM measurements. The proposed method assumes negligible invasion, negligible borehole rugosity, and lateral and vert ical homogeneity effects.  The successful application of the new interpretation method is documented with synthetic cases and field data. Water saturation estimates in shale formations obtained with the new interpretation method are compared to those obtained with conventional methods and laboratory measurements. Conventional interpretation of multi-frequency effective conductivity and permittivity well logs in a clay- and pyrite-rich shale formation generated water saturation estimates that varied up to 0. 5 saturation units, as a function of the operating frequency of the EM measurement, at each depth along the formation interval. A joint interpretation of multifrequency conductivity and permittivity is necessary to compute the oil-in-place estimates in such formations. Estimated values of water saturation, average grain size, and surface conductance of clays in that formation are in the range of 0.4 to 0.7, 0.5 micro meter to 5 micrometer, and 5×10 - 7 S to 9×10 - 7 S, respectively. The proposed method is a novel technique to integrate effective conductivity and permittivity at various frequencies. In doing so, the method generates frequency-independent oil-in-place estimates, prevents under-estimation of hydrocarbon saturation, and identifies by-passed zones in shales.

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American Association of Petroleum Geologists (AAPG)
Search and Discovery Article

Relative permeability in shales is an important petrophysical parameter for purposes of accurate estimation of production rate and recovery factor, efficient secondary recovery, and effective water management. We present a method to estimate saturation-dependent relative permeability in shales based on the interpretation of the low-pressure nitrogen adsorption-desorption isotherm measurements. Relative permeability were determined for 30 samples from the gas — and oil — window of Eagle Ford and Wolfcamp shale formations. These sample have low-pressure helium porosity (LPHP) in the range of 0.04 to 0.09 and total organic content (TOC) in the range of 0.02 to 0.06. The samples were ashed to study the effects of removal of organic matter on the pore size distribution, pore connectivity, and relative permeability. The estimated irreducible water saturation and residual hydrocarbon saturation are directly proportional to the TOC and LPHP, and exhibit 15% variation over the entire range. Pore connectivity, in terms of average coordination number, decreases by 33% with the increase in TOC from 0.02 to 0.06. The estimated fractal dimension is close to 2.7 for all the samples. The estimated relative permeability of aqueous phase and that of hydrocarbon phase at a given saturation is inversely proportional to the TOC. Relative permeability curves of the hydrocarbon phase for geological samples from various depths in a 100-feet interval indicate that the hydrocarbon production rate will vary drastically over the entire interval and these variations will increase as the hydrocarbon saturations reduce in the formation. In contrast, relative permeability curves of the aqueous phase suggest limited variation in water production rate over the entire interval. Further, based on the relative permeability curves, the hydrocarbon production is predicted to be negligible for hydrocarbon saturations below 50% and the water production is expected to be negligible for water saturations below than 80%. Efforts are ongoing to use the laboratory-based estimates to predict field-scale production and recovery rates.

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American Association of Petroleum Geologists (AAPG)
Search and Discovery Article

Measurements of fluid wetting characteristic are made routinely on rock samples. However, there are no published petrophysical models to differentiate between oil-wet and water-wet fractions of a reservoir sequence using commonly available log suites. This presentation builds on our previous publication that describes the unconventional reservoir petrophysical model we have developed (Holmes, 2014). Essentially, we define four porosity components, namely total organic carbon, clay porosity, effective porosity, and “free shale porosity.” This last component is an indirect calculation if the first three components do not sum to total porosity.  Porosity/resistivity plots can be constructed for the total porosity and interpreted in a standard fashion. These will mostly indicate a water-wet system where the effective porosity fraction is examined. A second porosity/resistivity plot compares resistivity with “free shale porosity,” and is clearly interpreted to indicate Archie saturation exponents of much larger than 2 — frequently in excess of 3 — indicating the oil-wet fraction of the reservoir system. Additionally, the plots suggest low to very low values of cementation exponent, ranging from 1.0 to 1.5.   Examples from the Bakken of Montana and North Dakota, the Niobrara of Colorado, and the Wolfcamp and Spraberry of Texas are presented showing quantitative distinction of water-wet vs. oil-wet reservoir components.

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American Association of Petroleum Geologists (AAPG)
Search and Discovery Article

Interpretations of thermal maturation provide critical data needed for both conventional and unconventional resource assessments. The absence of true vitrinite in pre-Devonian sediments eliminates one of the most commonly measured geothermometers used for thermal maturity determination. Programmed pyrolysis parameters like Tmax can be of limited utility given the maturity regime. However, other organic macerals are potentially available to constrain thermal maturity. The current organic petrology study has been undertaken to provide a very detailed comparison of reflectance measurements on pyrobitumens, “vitrinite-like” material and graptolites.  In the Appalachian Basin of North America, Cambrian-aged source rocks were deposited in shallow water mixed carbonate-siliciclastic depositional environments. Solid pyrobitumen material is found to occur in both lenticular lens/layer morphology as well as distinct pore-filling angular varieties. Published formulas to calculate Equivalent Reflectance (Eq. Ro) from solid bitumens have been applied to these discrete morphological populations. In addition, a newly developed formula to calculate Eq. Ro from angular pyrobitumen (VRc=0.866*BRo ang + 0.0274) is introduced based upon statistical evaluation of reflectance readings from a global dataset. “Vitrinite-like” organic macerals were found in rare abundance within these potential source rocks, but their occurrence enables an independent comparison to pyrobitumen Eq. Ro values. Graptolites are another organic maceral that can be evaluated via organic petrology, but caution should be utilized since these tend to show a high degree of anisotropy. The results of this investigation provide additional geochemical guidance to assist geologists in more accurately interpreting thermal maturity in the Rome Trough region of the Appalachian Basin.

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American Association of Petroleum Geologists (AAPG)
Search and Discovery Article

Rock-Eval hydrogen index (HI) is often used to compare relative maturities of a source horizon across a basin. Usually, there are several measurements from the source horizon at a single well, and the mean hydrogen index is calculated, or the S2 is plotted against TOC. The slope of the best fit line through that data is used as the representative HI for that well (sometimes referred to as the ‘slope HI ’ methodology). There is a potential flaw in both these methodologies; however, that renders the calculated HI as misleading if the source horizon being examined is not relatively uniform in source quality, vertically in the stratigraphic column. From a geologic perspective, it would be unusual for the source rock quality not to vary vertically in the stratigraphic column. Organic matter input, preservation, dilution, and sediment accumulation rate typically vary in many depositional environments over the millions of years required to create a thick source rock package. Nevertheless, there are source rocks which do display remarkable source-quality uniformity from top to bottom of the stratigraphic package. We have examined source rocks from several basins where the source quality is relatively uniform over the stratigraphic column, and source rocks where the source quality varies greatly over the stratigraphic column. Methodologies to assess hydrogen index at specific wells for the se two scenarios differ. Most geoscientists may not be familiar with why a single technique is not suitable for both these scenarios, or how to correctly use hydrogen index as a relative maturation proxy in the case where source rock quality is not uniform. We will demonstrate how to determine if your source rock quality is uniform or varied relative to HI over the stratigraphic column, and how to assign a hydrogen index to the different source facies when that source rock quality is not uniform. Further we will illustrate how to estimate the original hydrogen index of the different source facies and assign each a transformation ratio. The transformation ratio is a better proxy for relative maturity, since different source facies may have different present-day hydrogen indices, but their present-day transformation ratio should be quite similar.

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American Association of Petroleum Geologists (AAPG)
Search and Discovery Article

The assessment of the natural temporal variability of source rock units is critical for the understanding of petroleum systems as changes in mineral matrix, organic matter (OM) concentration, and composition can significantly affect expulsion efficiency, primary and secondary migration processes, hydrocarbon quality as well as oil source rock correlation. Already small-scaled fluctuations within sediment successions can critically influence migration efficiency. High-resolution investigation of a well-preserved Lower Jurassic drill core (Toarcian Posidonia Shale) revealed seven discrete and systematic intervals of deviating source rock quality. These were composed of homogenized, non-laminated marls of light grey color, opposed to laminated dark grey background sedimentation. Both lithotypes differentiate not only in mineral composition, but particularly in OM content and quality. An average TOC content of app. 3.9 wt.% reached by the grey marl, is faced by an average TOC content of app. 7.8 wt.% measured for the laminated dark grey marls. Average hydrogen index for grey non-laminated marls was app. 550 mg HC/g TOC, whereas much higher source rock quality with 780 mg HC/g TOC was attained in the dark laminated marls. The marls lower OM concentration and inferior OM quality generates important domains for preferential migration of products, originated from the dark grey layers, or hydrocarbon cluster in case of limited migration into adjacent reservoirs. To assess the potential for preferential intake of hydrocarbons by the coarser-grained light marls and their qualification as migration avenues, artificial maturation experiments were performed with both lithotypes. Hydrocarbon generation was simulated by hydrous pyrolysis in two successive temperature steps 330 °C and 360 °C, covering an early maturity stage, as well as the end of the oil window. Both lithologies show striking differences, not only for the extract yield, but also for the timing of generation. OM quality differences were reflected by variable n-alkane distributions and molecular maturity parameters. High-resolution continuous data produced by non-destructive techniques allows to draw conclusions on i) source rock potential, ii) expulsion and migration processes , and iii) on prediction of petroleum accumulation within the sediment succession. High-resolution investigation in combination with artificial maturation experiments represent an easy-to-use tool in petroleum system analysis.

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American Association of Petroleum Geologists (AAPG)
Webinar
Virtual Webinar
Wednesday, 9 February 2022, 8:00 a.m.–9:00 a.m.

 This talk will provide information to better understand the principles of surface geochemistry (SG), how best to use SG data in exploration or development programs, how to develop a cost effective sampling and analytical program, and will also explore best practices for the interpretation and integration of SG data.

American Association of Petroleum Geologists (AAPG)
Field Seminar
Naples, Italy
Friday, 24 June Saturday, 25 June 2022, 8:00 a.m.–5:00 p.m.

Field Trip Leaders: Jean Borgomano – CEREGE, Aix-Marseille Université, France Michele Morsilli – University of Ferrara, Italy Themes The Gargano Promontory (southern Italy) offers the opportunity to investigate a complete carbonate facies transect from inner platform to basin and to reconstruct the various events that shaped and controlled the evolution of the Apulia Carbonate Platform during the Cretaceous and Paleogene. This area can be considered a wonderful outcrop analog to better understand and visualize facies, depositional geometries, stratigraphic relationships and to compare them with other carbonate platforms. The exposed carbonate rocks show well-preserved original reservoir properties and form relevant analogues of subsurface reservoirs located in different structural settings; e.g. inner platform palaeokarst (Ombrina Mare, Rospo Mare oil fields), subthrust setting (Monte Alpi, Tempa Rossa), slope, base-of-slope resedimented carbonate facies (Elsa, Miglianico, Aquila, Rovesti), as well as relevant for the comparison with the specular Adriatic Carbonate Platform (AdCP) or other Tethyan carbonate systems. Main goals of this field trip are the observation of the facies and stratigraphic architecture of the inner platform and of slope and base-of-slope units deposited during the Early - Late Cretaceous and Eocene, as well as the carbonate production and exporting/resedimentation processes. The Apulia Carbonate Platform represents a well-known case study of a carbonate platform with different evolution through time. Facies distribution from inner platform to base-of-slope, stratigraphic architecture and depositional geometries, together with retreat and drowning of the platform or margin collapses, and seismic-scale outcrops, in a relatively poorly deformed context, constitute a text book examples of a Cretaceous Carbonate System. Itinerary and Stops Day 1 Naples (or Bari airport) to Apricena by bus (travel about 3 h) Stop 1.1 - Apricena quarries district: stop on peritidal cycles of Lower Cretaceous, fractured and karst reservoir (outcrop analog of the Rospo Mare oil field). Lunch Stop 1.2 - Belvedere di Ruggiano: stop on scalloped/faulted platform margin of mid-Cretaceous and base of slope to basin facies associations. Night in Monte Sant’Angelo Day 2 Stop 2.1 ft-e: slope to basin facies of the Lower Cretaceous and facies observation of the resedimented succession of the Upper Cretaceous. Lunch Stop 2.2 Monte Sant’Angelo to Manfredonia road – Upper Cretaceous slope to base of slope facies and architecture of the systems. Stop 2.3 (optional) - Monte Saraceno-Mattinata: panoramic view of the Upper Jurassic-Lower Cretaceous sequence and Valanginian retreating/drowning of the Apulia Platform and depositional geometries of the Eocene clinoforms. End of the Excursion (travel to Naples or Bari airport)

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American Association of Petroleum Geologists (AAPG)
Field Seminar
Naples, Italy
Tuesday, 21 June 2022, 8:00 a.m.–5:00 p.m.

Field Trip Leaders: Alessandro Iannace Stefano Tavani Mariano Parente (University of Naples Federico II, Italy) Themes The Cretaceous platform carbonates of the Sorrento Peninsula offer wonderful outcrop analogues for the reservoirs of the Monte Alpi and Tempa Rossa oil fields of subsurface Basilicata and for fractured carbonate reservoirs of other Tethyan carbonate systems. During this 1-day field trip we will see how the facies, diagenetic characters and stacking patterns of cyclical Barremian-Albian inner platform carbonates controls mechanical stratigraphy and fracture distribution. We will look at the fracture network at different scales, from stratabound fractures to reservoir-scale fracture corridors, combining panoramic observations of subvertical cliffs of the Mt. Faito ridge, exposing a >300m thick stratigraphic interval, with detailed observations of the same beds along roadcuts. Then, we will move to a road cut near Positano where we will observe a small-scale intraplatform basin, developed in Aptian-Albian carbonates, focusing on soft-sediment deformation, organic-rich dolostones, fault-zone architecture and breccia bodies. Itinerary and Stops Transfer from Naples to Mt Faito by minibuses (about 1h drive) Stop 1 – Ticciano village: general introduction to the geology of the southern Apennines and to the Apennine Carbonate Platform; panorama of the Mesozoic platform carbonates of the Monte Faito ridge Stop 2 – Croce dell’Eremita roadcut: facies and fracture distribution of Barremian-Albian inner platform interbedded dolostones-limestones Lunch Stop 3 – Santa Maria del Castello: panoramic view of Monte Conocchia cliff: distribution and arrest of vertical through-going joints and fracture corridors in a seismic scale carbonate platform exposure Stop 4 – roadcut north of Positano: middle Cretaceous synsedimentary tectonics, soft sediment deformation, organic-rich dolostones and breccia bodies in a small intraplatform trough. Driving back to Naples (about 90min drive)

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American Association of Petroleum Geologists (AAPG)
Field Seminar
Houston, Texas
Friday, 1 April 2022, 8:00 a.m.–1:00 p.m.

Denbury Inc. has been operating a continuous CO2 EOR flood in the West Hastings oil field since December 2010 resulting in the associated storage of over 26 million MT of CO2 and 31 million barrels of tertiary oil produced. As part of the tour, Denbury geologists and engineers will provide an overview of the field history; current operations and CO2 management; and a discussion of the structure, stratigraphy, and reservoir characteristics of the Frio Fm.

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American Association of Petroleum Geologists (AAPG)
Field Seminar
Houston, Texas
Friday, 1 April 2022, 8:00 a.m.–4:00 p.m.

This course will explore the best techniques and workflows when approaching a whole core analysis program where the end goal is to mitigate risk associated with any carbon monoxide/dioxide injection project.

American Association of Petroleum Geologists (AAPG)
Workshop
Lviv, Ukraine
Tuesday, 31 May – Wednesday, 1 June 2022, 8:00 a.m.–5:00 p.m.

Join us for a workshop where experts will  explore the Carpathian foreland and the Dnieper-Donetsk rift basins with a focus not only on hydrocarbons, but the utilization of geothermal resources, hydrogen exploration and CCUS.

American Association of Petroleum Geologists (AAPG)
Short Course
Sunday, 25 September 2022, 8:30 a.m.–9:30 a.m.

Date: 25 September 2022 Time: 8:30am - 4:30pm Course Instructor: Alberto Ortiz, Net Zero Carbon Solutions Registration Fee: $530 Registration Deadline: 25 August 2022 Short Course registration is included as part of the GTW registration process. The petrophysical characterization of unconventional shale-type reservoirs has been one of the most approached and relevant issues in the oil and gas industry in the last 8 years. This is because after several years, the operating companies comprehended the impact that an appropriate characterization of the reservoir has on their project economics. Another reason for this were the technical obstacles encountered in the measurement of petrophysical properties such as porosity, saturation and permeability due to the complexity of this type of reservoir. Obstacles and limitations not only relate to laboratory measurements but also to electrical logging tools. As a consequence of this, nowadays, petrophysical evaluations in this type of reservoir do not have standardized workflows established and accepted worldwide as is the case for conventional reservoirs. This motivates the professionals involved in the study of this type of rocks to dedicate a lot of effort in the validation of the technologies used, and sometimes it is difficult for them to understand the results, the evaluation of uncertainties and the construction of petrophysical models with results and representative parameters of the subsurface conditions. This course will focus on providing key knowledge for a better characterization of the rock both in the aspects related to the matrix represented by mineralogy and kerogen as well as the fluids present. The approach will be based on the convergence of different technologies that support and give robustness to the results. The contents that will be provided will include laboratory testing techniques and petrophysical evaluation of electrical well logs for unconventional shale-type reservoirs. The contents provided will cover a variety of studies based on the most diverse physical principles that will include the latest advances and techniques used in the industry such as Nuclear Magnetic Resonance, Spectroscopy, Dielectric, Computed axial tomography and SEM images, among others. As a result of this, attendees will have tools that allow a more comprehensive understanding of this type of rocks, a better assessment of the uncertainty of the model used and the necessary steps to improve its precision, accelerating the learning curve. The contents provided will also allow knowing the critical parameters that must be taken into account for the definition of areas to be drilled. Course Topics Reservoir heterogeneity characterization from outcrops to lab data and electrical logging. Most relevant unconventional plays of the world. Main characteristics. The petrophysical model. Components and definitions, construction, uncertainties, strengths and weakness. Lab studies: porosity, saturation, mineralogy, organic geochemistry and permeability. Electrical logging response on unconventional shale plays: triple combo, NMR, NMR T1T2, nuclear spectroscopy, spectral GR, dielectric. The effect of maturity on kerogen. Challenges on water saturation calculation. Data integration. Interpretation workflows and core calibration.

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American Association of Petroleum Geologists (AAPG)
Workshop
Virtual Workshop
Tuesday, 8 March Wednesday, 9 March 2022, 8:00 a.m.–5:00 p.m.

This two-day virtual conference aims to bring together industrial and academic persons to present, explore and develop approaches that will benefit both sectors in the future. The virtual conference will focus on current techniques, the challenges and future solutions in understanding the Triassic stratigraphy of the North Sea, Norwegian Sea, West of Shetland, Atlantic margins, and northern Europe.

American Association of Petroleum Geologists (AAPG)
Workshop
Netherlands
Tuesday, 5 April Wednesday, 6 April 2022, 8:00 a.m.–5:00 p.m.

Plan to attend Geothermal Crossover Technology workshop 4 on 5-6 April 2022. The workshop will offer an exciting knowledge sharing and discussion platform where industry experts, country representatives and academia can share their visions and perspectives on how the petroleum and geothermal industries can work together to create new opportunities to make geothermal energy exploration and production a reality.

American Association of Petroleum Geologists (AAPG)
Workshop
Sydney, Australia
Wednesday, 6 July Thursday, 7 July 2022, 8:00 a.m.–5:00 p.m.

As we transition to a new commercial reality for our industries, there has never been a more important time for Earth Scientists to take a seat at the table. This workshop is designed to share our knowledge of the petroleum sector with other branches of the geosciences, while learning from their experiences. Join us for this hybrid online and in-person workshop on 6 July 2022.

American Association of Petroleum Geologists (AAPG)
Workshop
Naples, Italy
Wednesday, 22 June Thursday, 23 June 2022, 8:00 a.m.–5:00 p.m.

Modelling carbonate sequences and reservoirs has always been a challenging task. Carbonate rocks are generated and subsequently modified by a large variety of biological, physical and chemical processes that start at the time of deposition and end today. To unravel the geological evolution and history of carbonate sequences is fundamental not only for understanding their hydrocarbons potential but also for their role as potential reservoirs for renewable energy (geothermal) or geological gas storage (CO2 and hydrogen). Several science disciplines are often involved to fully understand the characteristics of carbonate rocks and old approaches and new technologies and tools are nowadays applied in these types of sequences. The objective of this meeting is to allow scientists and engineers working on carbonate rocks in academia and industry to share their most recent experience, work, approaches and use of innovative technologies to increase the understanding of the very complex world of carbonates.

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American Association of Petroleum Geologists (AAPG)
Workshop
Muscat, Oman
Monday, 30 May – Wednesday, 1 June 2022, 8:00 a.m.–5:00 p.m.

Save the date! Join us for the upcoming AAPG Exploration in Mature Basins GTW to be held from 30 May – 1 June 2022 in Muscat, Oman. More information to follow soon.

American Association of Petroleum Geologists (AAPG)
Field Seminar
Barcelona, Spain
Wednesday, 30 March Thursday, 31 March 2022, 8:00 a.m.–5:00 p.m.

Trip leader(s): Josep Anton Muñoz, Pablo Granado and Eduard Roca Limit: 20 Participants The aim of this 2-day field trip is the recognition of the key structural features of a fold and thrust belt detached on salt that has resulted from the inversion of a previous passive margin. To achieve this objective, some of the key and most spectacular localities of the southern Pyrenees have been selected along the ECORS-Pyrenees transect. This is a reference cross-section provided that for many years a huge amount of geological and geophysical data sets has been collected and integrating into a kinematic model of the South-Pyrenean fold and thrust belt. Subsurface data (well logs and seismic sections) will be combined with field observations. One of the main characteristics of the southern Pyrenees is the preservation of the synorogenic sediments since the earlier stages of deformation, which not only provide time constraints but also allow us discussion of kinematics of fault-related folds and thrust systems. Finally, the mild contractional deformation permits deciphering the initial geometry of the rift system and the salt structures that configure the structural grain of the passive margin before the inversion, allowing discussion of the role that these structures play during the fold and thrust belt development. Itinerary: (day by day details of the trip) Day 1 Stop 1.1: The South-Pyrenean thrust front. Sant Llorenç de Montgai Structure of a frontal thrust system and related unconformities. Out of sequence thrusts and synorogenic sediments. The frontal thrust system of the South-central Pyrenees has been detached into the Triassic evaporites and involves a thin Mesozoic succession. It is characterized by an emergent thrust system during the sedimentation of upper Eocene and lower Oligocene continental sediments. Frontal thrusts were progressively buried by conglomerates, triggering a break-back thrusting sequence and the development of out-of-sequence thrusts bringing together strongly different Mesozoic successions, such as the Montroig thrust in the picture. Stop 1.2: The Ager basin and the Montsec thrust sheet. Fontllonga The Ager basin in the footwall of the Montsec thrust. The Montsec thrust sheet developed from the Paleocene to the Early Eocene as recorded by continental to shallow marine sediments deposited in its footwall (Ager basin) as well as in the Tremp-Graus piggy-back basin. The lower Eocene sediments of these basins grade westward into the slope succession filling the Ainsa basin at the footwall of the Montsec thrust. Stop 1.3: The frontal structure of the Montsec thrust sheet. Ametlla (optional: Montrebei) Fault-propagation fold related with the inversion of Early Cretaceous extensional faults and growth deltaic sediments in the footwall syncline. The Montsec thrust sheet involves the northern part of the Upper Cretaceous foreland basin characterised by a strong subsident turbiditic trough at the footwall of the Bóixols thrust. These turbidites grade southward into a carbonatic platform that constitutes the backbone of the Montsec Range (main ridge and cliff of the pictures). Underneath the Upper Cretaceous carbonates, some Early Cretaceous extensional faults are preserved in the hanging wall of the Montsec thrust, but others have controlled the development of a hanging wall frontal anticline. The geometry of this anticline as well as the structure of the growth sediments in the footwall Ager syncline are visible in the field. The subthrust geometry will be discussed integrating surface observations and the available seismic and well data. Overnight in Tremp Day 2 Stop 2.1: The Sant Corneli-Bóixols anticline Inversion of the rift margin The Sant Corneli-Bóixols anticline is the most prominent frontal structure of the Bóixols thrust sheet in the central Pyrenees. This fold trends east–west and crops out for greater than 40 km along strike. The Sant Corneli-Bóixols anticline involves a thick Mesozoic succession detached on top of Triassic evaporites. The prefolding sequence consists of up to 5 km of prerift, synrift, and postrift carbonates ranging in age from Jurassic to Upper Cretaceous. Synfolding Upper Cretaceous sediments start with the upper Santonian carbonates and continue with a succession of Campanian and Maastrichtian marls and turbidites. The Sant Corneli–Bóixols anticline is an example of an inversion fold developed along the rift margin of the Lower Cretaceous basin. Its geometry is related with the inverted extensional system. In particular, the three-dimensional geometry, including the saddles between culminations, is inherited from the previous transfer faults of the segmented rift margin. Available seismic data and 3 exploratory wells constrain the geometry at depth. Stop 2.2: The synororgenic Paleogene conglomerates Inverted Lower Cretaceous basin and Eocene-Oligocene synorogenic conglomerates at Collegats gorge. Stop 2.3 (optional): The Sopeira and Aulet minibasins. Sopeira Minibasins developed by extensional collapse and salt evacuation during the thermal subsidence at the southern Pyrenean rift margin. Inversion of these mini-basins at the early stages of Pyrenean contractional deformation during Late Cretaceous. Additional logistic information Transportation Transportation will be with a small bus, assisted by minivans to have access to some of the outcrops. Physical demand, equipment and safety This is an easy field trip with very easy and limited hikes to get to the outcrops. Outcrops will be from main sealed roads. Safety vests will be available, to be used by everybody of the group wherever required and asked to. There will be First Aid Kits available in each car during fieldwork. Climate The climate during mid-end November in the fieldwork area can be cold and rainy, although dry and sunny days may occur as well. The temperature for November in Tremp can range between 30C and 170C. Participants should be prepared in case we should encounter bad weather and you should bring warm and waterproof clothes and suitable hiking boots. -->

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American Association of Petroleum Geologists (AAPG)
Workshop
Lisbon, Portugal
Wednesday, 18 May Thursday, 19 May 2022, 8:00 a.m.–5:00 p.m.

This 2-day conference brings together diverse experts working on modern and ancient turbidite, MTDs, contourite and hybrid/mixed systems in order to improve the present-day knowledge, models and predictive power.

American Association of Petroleum Geologists (AAPG)
Field Seminar
Lisbon, Portugal
Monday, 16 May Tuesday, 17 May 2022, 8:00 a.m.–5:00 p.m.

Come along on this 2-day field seminar and tour outcrops in the Serra de Montejunto, just north of Lisbon and on the coast from Porto Novo to Paimogo. Instructors: Ricardo Pereira, (PARTEX Oil and Gas & Instituto Dom Luiz) Gil Machado (ChronSurveys Lda & Instituto Dom Luiz) Fees: To be determined Includes: Hotel Ground Transporation Snacks and Refreshments Lunch and Dinner Guidebook Departure Time/Location 16 May 2020 8:30am SANA Metropolitan Hotel Note:Transportation to start point is not included in the costs of this trip. Please bring clothing for hot day time temperatures (sun hat/ sun glasses/ sun cream etc.). Participants must wear suitable and comfortable light trekking shoes. Aims To gain or increase an understanding of the tectono-sedimentary processes of continental extension and rifting supported by outcrop observations, with focus on deep-depositional marine systems. Discuss implications for prospective petroleum systems. Promote debate and nourish new insights between attendants. About the Field Trip The Lusitanian Basin records the proximal events of syn- to post rift evolution of the hyper-extended West Iberian Margin, showing some outstanding examples of the combined tectono-stratigraphic depositional systems. Here, the Late Jurassic reveals diverse aspects of mixed marine depositional systems including not only submarine fans and turbidites, but also the build-up of carbonate reefs and shoreface to fluvial clastic sequences. Throughout the fieldtrip the different depositional aspects can be observed in detail to demonstrate how such depositional systems can vary in time and space. Observation of these outcrops allows a better understanding on how deep-water depositional systems can change within a sub-basin and help improving the understanding of reservoir properties. Itinerary Day 1 (16th May 2022) Stop # Location Relevant Aspects 1 Vila Franca de Xira Intro-Overview 2 Castanheira Coarse grain proximal depositional systems; Fault slope deposits 3 Arruda Marine shales and interbedded clastic deposits 4 Ota Late Jurassic marine reefs 5 Montejunto-Vila Verde Marine shales and interbedded clastic deposits 6 Wrap-up at the Hotel   Day 2 (17th May 2022) 1 Consolação-São Bernardino Shaly marine deposits of the Abadia Fm. (Kimm.) 2 Paimogo Shoreface to fluvial deposits Late Jurassic 3 Porto Novo Shoreface to fluvial deposits Late Jurassic 4 Santa Cruz Late Jurassic turbidites

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American Association of Petroleum Geologists (AAPG)
Workshop
Barcelona, Spain
Monday, 28 March Tuesday, 29 March 2022, 8:00 a.m.–5:00 p.m.

This workshop brings together experts from academia and industry from a range of disciplines to share experiences, new approaches, new data and new ways of integrating information that can help in reducing the uncertainties related to the exploration activities in Thrust Belt Systems.

American Association of Petroleum Geologists (AAPG)
Workshop
Manama, Bahrain
Monday, 26 September Wednesday, 28 September 2022, 8:00 a.m.–5:00 p.m.

The workshop aims to provide a comprehensive understanding of the source rocks in the Middle East. The technical program is developed in a way that coves the depositional environments and transport processes, basin modeling and detailed rock characterisation including geochemisty, geomechanics and petrophysics.

American Association of Petroleum Geologists (AAPG)
VG Abstract

This is a less-technical education topic. It can be condensed to an hour or given as 2 two-hour sessions. It stresses selected controversial aspects of fracking that touch some combination of environment and economics and includes a short video of how fracking is done.

Request a visit from David Weinberg!

American Association of Petroleum Geologists (AAPG)
VG Abstract

The following short course option was developed for geology and geophysics students that have not had much exposure to how geoscience is applied in industry. It can be tailored for undergraduate juniors and seniors or graduate students. The agenda can be modified to meet specific needs and time constraints.

Request a visit from Fred Schroeder!

American Association of Petroleum Geologists (AAPG)
VG Abstract

The carbonate sequences that were deposited in the now exhumed Tethyan Ocean influence many aspects of our lives today, either by supplying the energy that warms our homes and the fuel that powers our cars or providing the stunning landscapes for both winter and summer vacations. They also represent some of the most intensely studied rock formations in the world and have provided geoscientists with a fascinating insight into the turbulent nature of 250 Million years of Earth’s history. By combining studies from the full range of geoscience disciplines this presentation will trace the development of these carbonate sequences from their initial formation on the margins of large ancient continental masses to their present day locations in and around the Greater Mediterranean and Near East region. The first order control on growth patterns and carbonate platform development by the regional plate-tectonic setting, underlying basin architecture and fluctuations in sea level will be illustrated. The organisms that contribute to sequence development will be revealed to be treasure troves of forensic information. Finally, these rock sequences will be shown to contain all the ingredients necessary to form and retain hydrocarbons and the manner in which major post-depositional tectonic events led to the formation of some of the largest hydrocarbon accumulations in the world will be demonstrated.

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Request a visit from Keith Gerdes!

American Association of Petroleum Geologists (AAPG)
VG Abstract

Analysis of microseismicity induced by hydraulic fracture stimulation in the Marcellus Shale shows changes in stress state for different zones of failure. During the treatment, shear failure occurs on both the J1 and J2 fracture orientations in response to different maximum stress orientations, indicating localized changes in the orientation during the treatment. Reactivation of a fault near the wellbore is associated with failure mechanisms with a higher volumetric component, indicating possible inflation of faults and fractures by the introduction of the slurry. Quantification of the stress conditions that are associated with inflation could potentially be used to optimize the stimulation by identifying which fractures will preferentially take on slurry volume.

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Request a visit from Sherilyn Williams-Stroud!

American Association of Petroleum Geologists (AAPG)
VG Abstract

This lecture will discuss the differences between carbonates and siliciclastics from their chemical composition through their distributions in time and space. Building on these fundamental differences, we will explore the challenges carbonates pose to petroleum geologists in terms of seismic interpretation, reservoir quality prediction, field development, etc. Peppered with humorous personal stories, still raging academic debates, and the heartfelt frustrations of real industry professionals, the aim is to inspire students and young professionals to rise to the occasion and embrace the reservoir rocks that petroleum geologists love to hate.

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Request a visit from Noelle Joy Purcell!

American Association of Petroleum Geologists (AAPG)
VG Abstract

Production from unconventional petroleum reservoirs includes petroleum from shale, coal, tight-sand and oil-sand. These reservoirs contain enormous quantities of oil and natural gas but pose a technology challenge to both geoscientists and engineers to produce economically on a commercial scale. These reservoirs store large volumes and are widely distributed at different stratigraphic levels and basin types, offering long-term potential for energy supply. Most of these reservoirs are low permeability and porosity that need enhancement with hydraulic fracture stimulation to maximize fluid drainage. Production from these reservoirs is increasing with continued advancement in geological characterization techniques and technology for well drilling, logging, and completion with drainage enhancement. Currently, Australia, Argentina, Canada, Egypt, USA, and Venezuela are producing natural gas from low permeability reservoirs: tight-sand, shale, and coal (CBM). Canada, Russia, USA, and Venezuela are producing heavy oil from oilsand. USA is leading the development of techniques for exploring, and technology for exploiting unconventional gas resources, which can help to develop potential gas-bearing shales of Thailand. The main focus is on source-reservoir-seal shale petroleum plays. In these tight rocks petroleum resides in the micro-pores as well as adsorbed on and in the organics. Shale has very low matrix permeability (nano-darcies) and has highly layered formations with differences in vertical and horizontal properties, vertically non-homogeneous and horizontally anisotropic with complicate natural fractures. Understanding the rocks is critical in selecting fluid drainage enhancement mechanisms; rock properties such as where shale is clay or silica rich, clay types and maturation , kerogen type and maturation, permeability, porosity, and saturation. Most of these plays require horizontal development with large numbers of wells that require an understanding of formation structure, setting and reservoir character and its lateral extension. The quality of shale-gas resources depend on thickness of net pay (>100 m), adequate porosity (>2%), high reservoir pressure (ideally overpressure), high thermal maturity (>1.5% Ro), high organic richness (>2% TOC), low in clay (<50%), high in brittle minerals (quartz, carbonates, feldspars), and favourable in-situ stress. During the past decade, unconventional shale and tight-sand gas plays have become an important supply of natural gas in the US, and now in shale oil as well. As a consequence, interest to assess and explore these plays is rapidly spreading worldwide. The high production potential of shale petroleum resources has contributed to a comparably favourable outlook for increased future petroleum supplies globally. Application of 2D and 3D seismic for defining reservoirs and micro seismic for monitoring fracturing, measuring rock properties downhole (borehole imaging) and in laboratory (mineralogy, porosity, permeability), horizontal drilling (downhole GPS), and hydraulic fracture stimulation (cross-linked gel, slick-water, nitrogen or nitrogen foam) is key in improving production from these huge resources with low productivity factors.

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Request a visit from Ameed Ghori!

American Association of Petroleum Geologists (AAPG)
VG Abstract

The following short course option was developed for geology and geophysics students that have not had much exposure to how geoscience is applied in industry. It can be tailored for undergraduate juniors and seniors or graduate students. The agenda can be modified to meet specific needs and time constraints. Contact the presenter to discuss options.

Request a visit from Fred Schroeder!

American Association of Petroleum Geologists (AAPG)
VG Abstract

Hydraulic fracturing has been around for decades. This talk describes some of the first applications of the technology, how it developed over time, and our current understanding of its impacts with some discussion of both water and earthquake hazards.

Request a visit from Sherilyn Williams-Stroud!

American Association of Petroleum Geologists (AAPG)
VG Abstract

The following short course option was developed for geology and geophysics students that have not had much exposure to how geoscience is applied in industry. It can be tailored for undergraduate juniors and seniors or graduate students. The agenda can be modified to meet specific needs and time constraints. Contact the presenter to discuss options.

Request a visit from Fred Schroeder!

American Association of Petroleum Geologists (AAPG)
VG Abstract

In comparison with the known boundary conditions that promote salt deformation and flow in sedimentary basins, the processes involved with the mobilization of clay-rich detrital sediments are far less well established. This talk will use seismic examples in different tectonic settings to document the variety of shale geometries that can be formed under brittle and ductile deformations.

Request a visit from Juan I. Soto!

American Association of Petroleum Geologists (AAPG)

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