Rich Source Rocks Research Articles

The H2 potential of the Colombian coals in natural conditions

Coal gasification to manufacture dihydrogen (H2) has long been known as a surface process. Recent works have also highlighted the H2 generating potential of the Organic Matter (OM). The evolution of OM generates H2 all along the process but this gas is only expected to remain as free H2 after the maturation and expulsion of the hydrocarbons (HC) which means at a high temperature of above 200 °C. In this paper we studied the potential of three different tertiary coals from Amaga, La Jagua de Ibirico and Barrancas, all located in Colombia. Their H2 yields were studied using a pyrolyser and the kinetic of the H2 generation were quantified. All the studied coals are immature to early mature as source rock (SR) with large TOC content, between 66 and 83%, and good H2 potential. The highest values were found for the Barrancas area where the potential reached 25 mg H2/g TOC. The temperature corresponding to the peak of H2 generation is between 740 and 800 °C depending of the heating rate. This corresponds to the 200–300 °C for the H2 kitchen, even if the H2 generation starts before as already observed for continental organic rich source rock. Comparison with the other coals shows that H2 potential is linear with TOC. In the Colombian coals, the H2 yield in mg H2/g of rock is around 1/4 of the TOC content. In average, these coals have so a H2 yield about 10 000 mmol H2/kg of rock, two orders of magnitude above the “best” olivines. It should nevertheless be kept in mind that the extrapolation of these laboratory data to sedimentary basins remains unconstrained and will need to be refined when well data and modelling tools are available.

Innovation, Integration Enable Success in Guyana-Suriname Basin

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30946, “Innovation and Integration: Exploration History, ExxonMobil, and the Guyana-Suriname Basin,” by Audrey L. Varga, Matthew R. Chandler, and Worth B. Cotton, ExxonMobil, et al. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. _ Exploration in the Guyana-Suriname Basin has been a decades-long endeavor, including technical challenges and a lengthy history of drilling with no offshore success before the 2015 Liza discovery. The collection of extensive seismic data has been leveraged to enable successful exploration of multiple play types across the basin. Further data collection has enabled the operator to adopt interpretation techniques that are applied across the entire basin to characterize and understand the subsurface better. Historical Context The first wells drilled in the Guyana-Suriname Basin were onshore; the Rose Hall well in Guyana in 1941 first found oil shows. Rumors of oil in the region, and hopes that the prolific hydrocarbon systems present in Venezuela extended into Guyana and Suriname, led geologists from the Standard Oil Company to conduct initial reconnaissance and seismic and geochemical studies. Despite hints—in retrospect—of a favorable basin configuration and hydrocarbon presence, the decision was made to discontinue exploration activities. Through the 1950s and early 1960s, the region saw relatively low levels of activity. In 1960, the first well was drilled offshore Guyana, and, in 1964, the first offshore well was drilled in Suriname; both were dry. In 1965, the Geological and Mining Service of Suriname found heavy oil near the present-day Calcutta Field. This led to the discovery of the Calcutta, Tambaredjo, and Weg naar Zee heavy-oil accumulations, but only a thin reservoir and heavy oil were encountered. In 1975, Esso participated in the North Coronie-1 well in Suriname. The well found oil and gas shows, confirming the presence of immature but rich source rock that was age-equivalent to the prolific La Luna source in Venezuela. A reconnaissance 2D seismic program followed, and, in 1978, Esso drilled the first deepwater well at Demerara A2-1. This well also was dry but did find high-quality, immature source rock and weak oil and gas shows. After another disappointing well at FG-1 in French Guyana in 1978, Esso ultimately relinquished its licenses but noted the presence of excellent-quality source rocks and reservoirs. The onshore Tambaredjo field, discovered in the 1960s, did not start production until 1982. All in all, before the Liza discovery, more than 300 wells were drilled in the basin, with more than 200 of these dry. Of these, all 60 offshore wells were dry. Why, then, did exploration continue? Data Evolution In the mid- to late-1990s, the Guyana deepwater acreage was completely open. The data available to the operator’s geoscientists consisted of one or two seismic lines, approximately four offshore wells, and a Suriname onshore oil sample. At that time, a major change in global coverage and quality of satellite free-air gravity data occurred with the declassification of US military data. An internal project by the operator merged the Sandwell and Smith free-air gravity grid, available in the public domain, with Getech onshore Bouguer gravity grids to create a global gravity compilation. The operator’s researchers recognized the applicability of these data as a key technology enabler to update plate tectonic models and genetic basin analysis.

Organic geochemistry of Cambro-Ordovician succession of Ny Friesland, Svalbard, High Arctic Norway: Petroleum generation potential and bulk geochemical properties

Lower Paleozoic source rock (SR) characteristics and paleo-depositional environments are not well understood in the Barents Sea region. Organic and inorganic geochemical analyses of 17 carbonaceous samples from the Lower Cambrian Tokammane Formation, the Lower to Middle Ordovician Kirtonryggen and Valhallfonna formations in Ny Friesland, north-east Spitsbergen, show that there is a striking difference in petroleum generation potential and bulk geochemical properties between the Cambrian and Ordovician samples, and also within the Ordovician samples. TOC contents of <0.20 wt% for the Lower Cambrian Tokammane Formation samples indicate poor source rock richness. TOC contents in the range between 0.3 and 2.1 wt% and HI values between 123 and 424 mg HC/g TOC for the Valhallfonna and Kirtonryggen formation samples suggest significant variation in remaining petroleum generation potential with oil-prone (Type II) to mixed oil- and gas-prone (Type II/III) kerogen. Source rock maturity parameters such as Tmax (range 435–449 °C) and production indices for most Ordovician samples suggest relatively uniform maturity levels, ranging from the early-, to the peak-, of the oil generation window (i.e. ca. 0.70–0.85% Ro). This maturity level could have significant implication on the original petroleum potential assuming early generation from carbonate source rocks. Bulk carbon isotope data show that the Lower Cambrian Tokammane Formation samples are heavier (δ13C range from −28.4 to −28.8‰) than the Lower to Middle Ordovician Valhallfonna Formation samples (δ13C range from −29.7 to −30.9‰). The differences in the source rock richness and kerogen type within the Ordovician samples are attributed to organic facies variation. Tentatively, three categories of source rock organic facies (B, BC and C) are supported based on assumed-initial hydrogen index values for the Ordovician samples. The reliability of the indicated organic facies could be supported by addition of biomarker data from bitumen extracts. To our knowledge, this is the first study revealing the existence of a potential Lower Paleozoic source rocks in this part of the High Arctic, and this facies may also exist on the continental shelf to the north and NE.

Analysis of high-resolution airborne-magnetic data for hydrocarbon generation and preservation potential evaluation of Yola sub-basins, northern Benue Trough, northeastern Nigeria

High-resolution airborne-magnetic data acquired over the Yola extension of the northern Benue Trough, northeastern Nigeria, were analyzed to delineate rock distribution, define basement geometry, determine sedimentary thicknesses, and highlight structural framework among others for the hydrocarbon prospect evaluation of sub-basins in the extension. Filtered and refined magnetic intensity data were subjected to Analytic Signal, Horizontal and Vertical Tilt Derivatives and Euler deconvolution depth weighting analyses to enhance various geological features requisite for petroleum prospect evaluation. Sedimentary rock units flanked the northeast and south widely occur in the central part with volcanic rock intrusions delineated within the sedimentary terrain. Extracted lineaments (less than 5 km and up to 45 km) were observed to dominantly follow the established Benue Trough and Yola sub-basin evolutionary trend along the NE–SW and ESE–WNW directions, respectively. Three prominent sub-basins with sedimentary thicknesses in excess of 3 km and width of more than 60 km, separated by basement highs of mostly volcanic intrusions origin, were identified. The occurrence of relatively thick and extensive sub-basins which are underlain by structurally active basement rocks suggests relatively high geothermal gradient for generation of hydrocarbon from organic matter rich source rocks while the generated oil and gas are preserved within intra-sedimentary structural traps created when the basement fractures were reactivated.

Halogen ratios in crustal fluids through time—Proxies for the emergence of aerobic life?

Abstract Halogens (Cl, Br, I) are exceptional provenance tracers in crustal fluids because their ratios are not strongly altered during most fluid-rock interaction processes. The halogen systematics of metamorphic fluids are of particular interest because such fluids are key drivers of crustal-scale element fluxes and ore formation in orogenic belts, but they remain poorly studied due to analytical challenges. We present novel triple-halogen laser ablation–inductively coupled plasma–mass spectrometry (LA-ICP-MS) fluid-inclusion data from metamorphic systems ranging in age from Archean to Phanerozoic. Our results show that the halogen signatures in Phanerozoic metamorphic fluids are controlled by variable degrees of organic-matter interaction in their source rocks, leading to increased I/Cl and decreased Br/I ratios relative to seawater. By contrast, Archean metamorphic fluids from organic matter–rich source rocks have low I/Cl and very high Br/I ratios, distinctly different from any known fluid source signature. We propose that these signatures nevertheless are consistent with organic-matter interaction because dominantly prokaryotic Archean lifeforms did not yet produce iodine-bearing metabolites. This prevented biosequestration and accumulation of iodine-rich organic matter in sediments and imposed halogen signatures onto Archean metamorphic fluids entirely unlike those in younger fluids.

Source rock evaluation and fluid inclusion reconnaissance study of Carboniferous and Zechstein rocks in the northern margin of the Southern Permian Basin, onshore Denmark

Hydrocarbon exploration onshore Denmark has been unsuccessful with no commercial discoveries. Several potential plays have been identified of which the Zechstein carbonate play relying on organic-rich Zechstein (Z2) carbonates as source rock is considered the most promising. Additional source rocks might be lower Carboniferous calcareous and carbonaceous units. This study aims at documenting Palaeozoic source rock(s) in the Upper Mississippian/Lower Pennsylvanian and Zechstein Z2 cored sections in wells drilled in the northern margin of the Southern Permian Basin in the Danish Baltic Sea area. The source rock potential, organic matter composition, and thermal maturity was examined using Rock-Eval pyrolysis, vitrinite reflectance measurements, and organic petrography of cuttings and core samples from two wells. In addition, a fluid inclusion reconnaissance study was conducted on samples from four wells. The examined Upper Mississippian/Lower Pennsylvanian marine calcareous mudstones are thermally immature to marginally mature with a generally low TOC content consisting of minor amounts of dispersed vitrinite and inertinite and scattered yellowish fluorescing mainly terrigenous liptinite macerals. The source rock potential is nil to poor. The analysed Zechstein Z2 section is also thermally immature and consists of resedimented carbonate mudstones deposited in a marine environment on a slope. The mudstones are organic-lean with identifiable tiny vitrinite particles and some telalginite. The source rock quality is poor with a potential for some gas generation. Thus, identification of rich source rocks failed, but the occurrence of solid bitumen in the Zechstein Z2 suggests the presence of restricted source rock levels in the mudstones or migration from deeper richer source rock sections. Further, hydrocarbon fluid inclusions are direct evidence for petroleum generation and migration. The dark appearance, high vapour/liquid ratio at room temperature and their homogenisation behaviour clearly indicate a mixed hydrocarbon composition with methane and higher hydrocarbons, like gas condensate. This demonstrates the presence of a working petroleum system in the northern margin of the Southern Permian Basin in southern Denmark.

Cyclic Gas Injection EOR in Eagle Ford Can Increase Estimated Ultimate Recovery

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200427, “Evaluation of Eagle Ford Cyclic Gas Injection EOR: Field Results and Economics,” by George Grinestaff, SPE, Chris Barden, and Jeff Miller, SPE, Shale IOR, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. Cyclic-gas-injection-based enhanced oil recovery (CGEOR) in the Eagle Ford was begun in late 2012 by EOG Resources and, at the time of writing, has expanded to more than 30 leases by six operators (266 wells). An extensive EOR evaluation was initiated to analyze the results recorded in these leases. The authors write that CGEOR in Eagle Ford volatile oil can yield substantial increases in estimated ultimate recovery (EUR) with robust economics, depending on compressor use and field life. Introduction Eagle Ford Source Rock and Reservoir. The Eagle Ford shale represents some of the world’s richest source rocks. The Upper Cretaceous seafloor received abundant organic debris and preserved it in an anoxic environment. The low permeability of the shale and limestone helped generate hydrocarbons when pore pressure exceeded overburden pressure. The resulting natural fractures provided a means to expel oil, much of it migrating into the overlying Austin Chalk and Tertiary sandstones. The primary target area for produced-gas injection EOR is currently in the volatile oil window between 9,000 and 11,000 ft true vertical depth, which yields oil API gravity of greater than 40. Initial gas/oil ratio (GOR) typically ranges from 1,000 to 3,000 scf/bbl. Eagle Ford EOR History. The first large-scale CGEOR project was implemented in October 2014. Rapid development has occurred since then, but, in the complete paper, the authors present the first commercial EOR projects by EOG Resources because these have the longest CGEOR production history. Recent projects show more-efficient startup, cycling, and higher optimization of gas injection. Therefore, the analysis of EOR in this paper takes a conservative approach of using the first projects because they appear to have lower EOR recovery but more production history. Evaluation Methodology Unconventional EOR Work Flow. Analysis of CGEOR production and results has been completed using production history and reservoir simulation to provide a rigorous evaluation. The authors use a 14-component fracture element model with a very fine grid to predict well GOR, EUR, and reservoir behavior for the compositional process. The element model is then scaled up to mimic the average well for a given pad or lease, and then cycle operations are developed based on CGEOR simulation runs and criteria. Unconventional CGEOR provides a direct response after the first cycle of gas injection; however, the base depletion profile also is important for understanding economics for increased oil production or incremental EOR. A history match of the base depletion is first completed to match an average well at the pad level (approximately one 640-acre section with 10 to 14 wells). The element is then scaled up based on well completion, stimulated rock volume, and EUR for the base depletion.

Application of the Data on δ13C and δ18O of Carbonates for the Study of Unconventional Reservoirs on the Example of the Bazhenov Source Rocks, Western Siberia, Russia

This paper addresses potential application of data on stable carbon and oxygen isotope composition of carbonates for study of organic rich source rocks on the example of the Late Jurassic–Early Cretaceous Bazhenov Formation (West Siberian petroleum basin, Russia). Geochemical studies were conducted for sections located in central (most productive) and peripheral (northern and southern) regions of the Bazhenov Formation distribution area, containing deposits formed under different conditions. We identified key factors impacting stable isotope composition of carbonate minerals and established relation of their isotope composition to the formation conditions. Using a thermodynamic model of carbon and oxygen isotope exchange in the carbonate–water–carbon dioxide system, it is shown that variations in the isotope composition of secondary carbonates are affected by isotopic composition of primary carbonates in sediments and by the isotope exchange reactions with water and carbon dioxide, generated during the source rocks transformation. Our results demonstrate that stable isotope data for carbonates in the Bazhenov Formation together with standard geochemical methods can be efficiently applied to determine sedimentation conditions and secondary alteration processes of oil source rocks.

Combining Source Rock Kinetics and Vitrinite Reflectance in Source Rock Evaluation of the Bakken Formation, Williston Basin, USA.

The elements of Bakken Petroleum System consist of two source rocks with high underlying burial depths for significant hydrocarbon generation. However, this deep hydrocarbon generation process is dependent on its kinetic properties, thermal maturity, and geochemical properties. The statistical compensation effect is a complicating factor in the kinetic analyses of the Bakken Formation. In this study, we experimentally determined the kinetics of the Bakken formation source beds, observed the presence of the residual compensation effect, and numerically established a correlation between the kinetic parameters, thermal maturity indices (Tmax), and the vitrinite reflectance (VRo) and bitumen reflectance (BRo). First, we conducted source rock analysis to determine kinetic properties and the organic geochemical assays of reactive kerogen in the Bakken source beds. Finally, we incorporated previous established studies to generate numerical correlation for Tmax in terms of VRo and BRo reflectance. Our kinetic results show evidence of the residual compensation effect in the Bakken Formation when samples are repeatedly analyzed. The simultaneous linear expression of the residual compensation effect and the regression analysis of the solutions to the Kissinger equation for heating rate, yielded a kinetic parameter solution that correlates with Tmax. Furthermore, recalculated Tmax values established a correlation between the kinetic parameters, Tmax, VRo, and BRo. The application of state-of-the-art numerical correlations to measure subsurface kinetics, source rock richness, and burial-depth temperatures will enhance the accuracy of reservoir exploration and hydrocarbon production within the Bakken Formation.

Application of the Wide Field Electromagnetic Method for Oil and Gas Exploration in a Red-bed Basin of South China

Red-bed basins with rich hydrocarbon source rocks are widely distributed in south China, such as Banshi Basin in southern Jiangxi, which may have very good prospects for oil and gas exploration. However, due to poor ground conditions, and complex geological structures, seismic exploration and conventional electromagnetic methods cannot provide useful information for hydrocarbon evaluation. This study uses the wide field electromagnetic (WFEM) method to investigate the distribution and geoelectric characteristics of the target stratum of a red-bed basin in Jiangxi province, China. The inversion results demonstrate that the WFEM method could quickly delineate the favorable area and determine the location of the parametric well, confirming that the WFEM method is an effective geophysical exploration method for evaluating hydrocarbon resources in red-bed basins.

Geochemical Evaluation for the Hydrocarbon Potential of Source Rocks in the Anza Basin

Anza basin is located in the extensional arm of the central African rift system in the North-Eastern part of Kenya. Cretaceous sedimentary rocks were sampled from the four wells namely, Chalbi-3, Sirius-1, Ndovu-1 and Kaisut-1. Anza basin occurs on a fault block within a Paleocene-Cretaceous rift basin. The methodological approach used for the evaluation of source rocks included petrophysical and geochemical methods to ascertain their potential. Well sections with a higher shale-volume ratio were sampled for geochemical screening to determine the organic richness and thermal maturity of potential source rocks, respectively. Source rock with organic richness ≥ 0.5% were evaluated further for their petroleum potential using Rock-Eval pyrolysis to determine their thermal maturity, organo-facies and in-situ generated hydrocarbons present in sedimentary facies. The geochemical evaluation of rock samples from the drilled wells’ sections of Chalbi-3 and Sirius-1 confirmed both oil and gas potential. Gas Chromatography and Mass Spectrometry (GCMS) were used to characterize the biomarker signatures and oil-oil correlation of Sirius-1 samples. A predictive model was developed to integrate the petrophysical and geochemical data to reveal hydrocarbons’ potential in the Anza basin.

Why does not lithology correlate with gamma-ray spikes in the shaley source rocks of the Upper Jurassic Alge Member (southwestern Barents Sea)?

Prominent high-value gamma-ray spikes in the maximum flooding surfaces of the Middle Oxfordian-Kimmeridgian succession (Alge Member) display stratigraphic and regional variations in the southwestern Barents Sea. These variations suggest heterogeneities in the composition of the Alge Member, thus, challenging the common perception that this interval is a homogenous succession of organic-rich black shale. This study explores the overall variation in; clay mineral composition, source rock quality, minerals and macerals, core logs and seismic facies of the Alge Member. Gamma-log fluctuations were found to be independent of these variations. Uranium precipitates on sea bottom sediments when conditions change from oxic to anoxic. Fluctuations in sea level may result in such changes and, hence, guide gamma-ray responses. Sea level fluctuations also lead to a changing distance to the shoreline, which again influences sediment types, grain sizes, and source rock quality. Thus, indirectly sea level appears to be the common denominator, which sometimes matches source rock richness with spikes on gamma logs. Presence and absence of gamma-ray spikes are, hence, an additional tool to reveal the redox conditions in the SW Barents Sea, which has implications for the understanding of the paleogeography (or paleobathymetry) during deposition.

Geological conditions and gas-bearing evaluation of the Niutitang Formation shale in the Xixiang–Zhenba area, China

Black carbonaceous shale of the Niutitang Formation in the Xixiang–Zhenba area was found to be well developed and abundant in high-quality shale gas. However, few studies have been conducted in this area, and its reservoir-forming conditions are not clear. This study aims to analyse source rocks, reservoir characteristics and storage conditions of the Niutitang Formation shale in the Xixiang–Zhenba area using field investigations, drilling and logging, supplemented with laboratory experiments. Results of this study shows that the Niutitang Formation shale is deeply buried at 1500–4500 m and is mainly 10-110 m thick. The shale is widely distributed, thicker in the west, thinner in the east and is a highly mature organic rich source rock with kerogen type I and II. The shale stratum features a high content of brittle minerals, many natural cracks, and a low content of clay minerals which are mainly illite, followed by a mixed layer of illite and smectite. The shale reservoir is characterized by low porosity and permeability. In addition, the lithology is dense and acts as a good seal in this area while it has a high adsorption capacity and high gas-bearing potential. Overall, within the study area, the western, central, and southern parts have good structural preservation conditions. The Niutitang Formation in the study area shows excellent organic matter characteristics for shale gas generation as well as good geological conditions for shale gas accumulation.

Chapter 5 Interpretation of the origin and evolution of the Arabian Intrashelf Basin and the development of the Dhruma Atash, Tuwaiq and Hanifa sequences

Abstract This is the first of two chapters in which the data presented in the first four chapters of this Memoir are reviewed and interpreted. A summary cross-section across the basin from the Saudi outcrop to Abu Dhabi and the Tethyan margin is used to summarize the regional setting and sequences as interpreted in this Memoir. The key points illustrated by the summary cross-section are stated and discussed in the first part of this chapter. Two different interpretations for the eastern margin of the intrashelf basin are reviewed. In the first of these interpretations, the margin with the deeper waters of the Tethys Ocean shelf is adjacent to the intrashelf basin rim in Abu Dhabi, whereas in the second, preferred in this Memoir, a broad, shallow Tethyan shelf platform (200–300 km wide) extends from the intrashelf basin rim to the Tethys continental shelf edge. The implications of Late Jurassic exposure and erosion on the adjacent Tethyan shelf are discussed. The development of the Arabian Intrashelf Basin during the Callovian–late Oxfordian (the Tuwaiq Mountain Formation, the source rock and the Hanifa intervals and associated sequences) is interpreted and discussed with illustrations, including step-by-step facies maps. The interpretation integrates depositional, eustatic and tectonic factors in the evolution of the intrashelf basin. The interpretation in this Memoir is that the Arabian Intrashelf Basin began with isostatic and extensional subsidence on top of a broad Dhruma Atash Member platform, which had largely filled the accommodation space up to the wave base and to near sea-level. It developed fully into an intrashelf basin during the deposition of the Callovian Tuwaiq sequence, with rising sea-levels coincident with a productive shallow water carbonate factory resulting in a rim of shallow water carbonate. An end-Callovian to early Oxfordian lowstand terminated the Tuwaiq sequence on the basin rim. During the lowstand, restricted conditions in the basin deposited the rich Lower Hanifa source rock as a lowstand systems tract. As more normal conditions returned in a subsequent sequence, the source rock facies graded upwards into Hanifa reservoir facies, which partially filled the basin. Hanifa progradation was terminated by another lowstand during which a subaqueous gypsum/anhydrite marker bed was deposited in at least part of the remnant basin. Earlier interpretations of these sequences are also discussed.

Analysis of high-resolution aeromagnetic (HRAM) data of Lower Benue Trough, Southeastern Nigeria, for hydrocarbon potential evaluation

ABSTRACT The analyses of high-resolution aeromagnetic (HRAM) data of lower Benue Trough in southeastern Nigeria have delineated sections of the basin with requisite sedimentary thickness that could support the generation of oil and gas from right-type organic-matter rich source rock as well as identified intra-sedimentary structural framework that could aid hydrocarbon migration and restrain generated hydrocarbon within available reservoirs. The susceptibility and Analytic Signal (AS) maps derived from processed Gaussian-filtered and Reduced to Pole at Low Latitude (RTPLL) aeromagnetic data discriminate crystalline basement rocks from the sedimentary units. Likewise, many relatively shallow, short (900–1600 m) intra-geologic terrain linear structures and fewer long, deeper (>1.5–43 km) inter-geologic terrains crustal linear structures which reduce in population but increase in lateral extent and depth with increasing continuation distances were delineated from the processed Tilt Derivative (TDR) and the Horizontal components of the Tilt Derivatives grids at different Upward Continuation distances. Euler Deconvolution depth-weighting analyses determined depth to magnetic sources which ranges in value from 120 m above to 5 km below the Minna reference datum. Regions having sedimentary thickness in excess of 3 km with active intra-sedimentary structural elements qualify for further petroleum exploration campaign using other detailed geological and geophysical tools.

Effects of gas pressurization on the interpretation of NMR hydrocarbon measurements in organic rich shales

The estimation of total hydrocarbons (HCs) in place is one of the most important economic challenges in unconventional resource plays. Nuclear magnetic resonance (NMR) has proven to be a valuable tool in directly quantifying both hydrocarbons and brines in the laboratory and the field. Some major applications of NMR interpretation include pore body size distributions, wettability, fluid types, and fluid properties. However, for tight formations, the effects of the factors on NMR relaxation data are intertwined. One purpose of this study is to review the interpretation of NMR response of HCs in a tight rock matrix through illustrated examples. When comparing NMR data between downhole wireline and laboratory measurement, three important elements need to be considered: 1) temperature differences, 2) system response differences, and 3) pressure (mainly due to the lost gasses.) The effect of temperature on HCs would be presented with experimental results for bulk fluids. Whereas, the effect of pressure is investigated by injecting gas back into rock matrix saturated with original fluids. The experiments were performed within an NMR transparent Daedalus ZrO2 pressure cell, which operates at pressures up to 10,000 psi. The results show that, at ambient temperature and pressure, NMR responds to a fraction of HCs, which is volatile enough to be observed as an NMR relaxation sequence. The invisible fraction of HCs to NMR sequence at ambient condition can be up to 20% of the total extractable HCs. Molecular relaxation is impacted by fluid viscosity, pore size, and surface affinity. In other words, the fluid with higher viscosity (either due to temperature or gas loss), presenting in smaller pore, or highly affected by the pore surface, will relax faster, and would be partially invisible to NMR, especially in the field. This is critical to the interpretation of NMR response for liquid rich source rocks, in which all of the above molecular relaxing restrictions can be found. Thus, engineers can underestimate movable HCs by using routine core analysis data.

Petrography and Geochemistry of Bada’u and its Environ, Katsina State Northwestern Nigeria

The systematic studies of petrography and geochemistry of Bada’u revealed that the area are underlain by crystalline rocks of the Basement Complex, which is categorized as the low grade schist belt. The mapped area is situated within Malumfashi Local Government area of Katsina State, part of Malumfashi sheet 79 NW, which lies between latitudes 11051ʹ0.00˝N to 110 55ʹ00˝N and longitude of 70 32ʹ0.00˝E to 7035ʹ0.00˝E. The rock units were mapped in the sub-area on a scale of 1:25,000, covering an area of about 40km2. The major lithological units mapped in the study area comprises basically of mica schist intercalated with quartzites, porphyritic granites, and minor lithology which includes granite-gneiss, gneiss. The study area shows the evidence of post and syn-Tectonic (Primary and Secondary) structures such as joints, fracture, zenolith, and quartz veins. The dominant joint trend and Quartz veins of the study area are N-S E-W directions respectively which follows the general trend of structures resulting from Pan-African Orogeny. Seven rock samples were collected for both petrography and geochemical studies (2 samples of granites, two samples of gneiss and three samples of mica schist). The major minerals observed under plane polarized and cross polarized light microscope of the granite-gneiss, mica schist and granites are Quartz, feldspar (orthoclase), and micaceous minerals (Biotite and Muscovite) respectively. The geochemical result shows that the rock units within the study area have high percentage of SiO2 and Al2O3 concentration in wt%. This suggest that the rocks within the study were formed from a silica rich source. The granite within the area are peraluminous and shows calc-alkaline characteristics, and occur in syn collision environment as revealed under various geochemical classification plots. The gneiss in the area also have high percentage of SiO2 and Al2O3, suggesting a calc-alkaline affinity. The lesser amount of Na2O against K2O reflect an abundance of K-feldspars rock forming silicate. The mica schist also has high percentage of SiO2 and Al2O3, the high aluminium enrichment in mica shcist reflects the control of their composition by aluminum clay minerals, the mica schist specifically has high Barium contents which indicate K – feldspar rich source rock. The chemical concentration of Rb is similar to their derivation from shales or metapelites, which is a reflection of their origin.

Organic geochemistry of oil seeps from the Abu-Jir Fault Zone in the Al-Anbar Governorate, western Iraq: Implications for early-mature sulfur -rich source rock

Organic geochemical methods were performed on four oil seep samples collected from the Abu-Jir Fault Zone (AJFZ) in the Al-Anbar Governorate, western Iraq. These oil seeps have undergone biodegradation, showing large unresolved complex mixture (UCM) shapes, with degradation of normal alkanes and isoprenoids. The inorganic elements of the Abu-Jir oil seeps, i.e., S, Ni and V, suggest a marine carbonate-rich source rock deposited under reducing environment conditions. The biomarker ratios and parameters of hopane and sterane further suggest that the oil seeps were derived from source rock rich in lipids from phytoplankton and bacteria with less contribution of terrigenous organic debris. The chemical maturity indicators show that the Abu-Jir oil seeps were generated from early mature sulfur -rich source rock, thus in association with a high S content of more than 1.93%. The geochemical characteristics of the analyzed oil seep samples are similar, which is consistent with most of the crude oils in the northern and southern basins in Iraq, and were generated from the Middle Jurassic Sargelu Formation. The overall geochemical correlations and geological information confirm that the Abu-Jir Faultoil seeps in the western Iraq were sourced from the Middle Jurassic Sargelu Formation that reached an early maturity level of oil-generation window and that they migrated into the ground surface through the Abu-Jir major fault during the middle Miocene.

Assessing organic richness of source rocks through integration of acoustic logs and microresistivity images

Assessing organic richness of source rocks through integration of acoustic logs and microresistivity images

Organic Geochemical Characteristics of Source Rocks of Hongshuizhuang Formation in the Mengjiawopu Section of Lingyuan-Ningcheng Basin in North China

Through the regional geological survey, outcrop section measurement and other field geological work, a block of black shale is found at the outcrop of Mengjiawopu Section of Hongshuizhuang Formation in Jixian County, and organic geochemical source rock analysis and evaluation methods are used to study the source rocks in Hongshuizhuang Formation. The set of source rocks is mainly gray-black silty mudstone and gray-black shale, with a cumulative thickness of 78 m; the total organic matter (TOC) is generally high, with an average content of 1.35%, of which good and rich source rock samples account for 86%. A combined analysis of the stable carbon isotope of kerogen, the correlation between Pr/nC17 and Ph/nC18, and the ratio of saturated hydrocarbon to aromatic hydrocarbon identifies that the organic matter is mainly Type Ⅱ kerogen; the equivalent vitrinite reflectance Ro of organic matter is from 1.68% to 1.94%. Rc, the correlation of the methylphenanthrene index (MPI) against the vitrinite reflectance is from 1.63% to 1.81%, with an average of 1.71%, and the Odd/Even Predominance (OEP) value is between 0.87 and 1.11, both indicating that the source rocks of the Hongshuizhuang Formation are at the stage of high to over maturation. In summary, the set of source rocks in Hongshuizhuang Formation is characterized by high organic matter content, good kerogen types, and high to over maturation stage.