scholarly journals Episodic hydrocarbon charge in tight Mississippian reservoirs of Central Oklahoma, USA: Insights from oil inclusion geochemistry

2021 ◽  
Vol 123 ◽  
pp. 104742
Author(s):  
Ibrahim Atwah ◽  
Sahar Mohammadi ◽  
J. Michael Moldowan ◽  
Jeremy Dahl
Keyword(s):  
Hydrocarbon Charge

Petroleum Systems Analysis of The Tungkal PSC Area, South Sumatra – A Means of Adding New Life to A Mature Area

2020 ◽  
Author(s):  
A. Livsey
Keyword(s):  
Seismic Data ◽  
Systems Analysis ◽  
Generation Model ◽  
Hydrocarbon Accumulation ◽  
Petroleum Systems ◽  
Oil Generation ◽  
Exploration Risk ◽  
Exploration Area ◽  
Hydrocarbon Charge ◽  
Surface Geology

South Sumatra is considered a mature exploration area, with over 2500MMbbls of oil and 9.5TCF of gas produced. However a recent large gas discovery in the Kali Berau Dalam-2 well in this basin, highlights that significant new reserve additions can still be made in these areas by the re-evaluation of the regional petroleum systems, both by identification of new plays or extension of plays to unexplored areas. In many mature areas the exploration and concession award history often results in successively more focused exploration programmes in smaller areas. This can lead to an increased emphasis on reservoir and trap delineation without further evaluation of the regional petroleum systems and, in particular, the hydrocarbon charge component. The Tungkal PSC area is a good example of an area that has undergone a long exploration history involving numerous operators with successive focus on block scale petroleum geology at the expense of the more regional controls on hydrocarbon prospectivity. An improved understanding of hydrocarbon accumulation in the Tungkal PSC required both using regional petroleum systems analysis and hydrocarbon charge modelling. While the Tungkal PSC operators had acquired high quality seismic data and drilled a number of wells, these were mainly focused on improving production from the existing field (Mengoepeh). More recent exploration-driven work highlighted the need for a new look at the hydrocarbon charge history but it was clear that little work had been done in the past few year to better understand exploration risk. This paper summarises the methodology employed and the results obtained, from a study, carried out in 2014-15, to better understand hydrocarbon accumulation within the current Tungkal PSC area. It has involved integration of available well and seismic data from the current and historical PSC area with published regional paleogeographic models, regional surface geology and structure maps, together with a regional oil generation model. This approach has allowed a better understanding of the genesis of the discovered hydrocarbons and identification of areas for future exploration interest.

Acquire Ocean Bottom Seismic Data and Time-Lapse Geochemistry Data Simultaneously to Identify Compartmentalization and Map Hydrocarbon Movement

2021 ◽  
Author(s):  
Rick Schrynemeeckers
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
Time Lapse ◽  
Field Trials ◽  
Detection Methods ◽  
Ocean Bottom ◽  
Field Development ◽  
Dense Grid ◽  
Hydrocarbon Charge ◽  
Sweet Spots

Abstract Current offshore hydrocarbon detection methods employ vessels to collect cores along transects over structures defined by seismic imaging which are then analyzed by standard geochemical methods. Due to the cost of core collection, the sample density over these structures is often insufficient to map hydrocarbon accumulation boundaries. Traditional offshore geochemical methods cannot define reservoir sweet spots (i.e. areas of enhanced porosity, pressure, or net pay thickness) or measure light oil or gas condensate in the C7 – C15 carbon range. Thus, conventional geochemical methods are limited in their ability to help optimize offshore field development production. The capability to attach ultrasensitive geochemical modules to Ocean Bottom Seismic (OBS) nodes provides a new capability to the industry which allows these modules to be deployed in very dense grid patterns that provide extensive coverage both on structure and off structure. Thus, both high resolution seismic data and high-resolution hydrocarbon data can be captured simultaneously. Field trials were performed in offshore Ghana. The trial was not intended to duplicate normal field operations, but rather provide a pilot study to assess the viability of passive hydrocarbon modules to function properly in real world conditions in deep waters at elevated pressures. Water depth for the pilot survey ranged from 1500 – 1700 meters. Positive thermogenic signatures were detected in the Gabon samples. A baseline (i.e. non-thermogenic) signature was also detected. The results indicated the positive signatures were thermogenic and could easily be differentiated from baseline or non-thermogenic signatures. The ability to deploy geochemical modules with OBS nodes for reoccurring surveys in repetitive locations provides the ability to map the movement of hydrocarbons over time as well as discern depletion affects (i.e. time lapse geochemistry). The combined technologies will also be able to: Identify compartmentalization, maximize production and profitability by mapping reservoir sweet spots (i.e. areas of higher porosity, pressure, & hydrocarbon richness), rank prospects, reduce risk by identifying poor prospectivity areas, accurately map hydrocarbon charge in pre-salt sequences, augment seismic data in highly thrusted and faulted areas.

Geologic-geochemical and modelling studies of hydrocarbon migration in the South Caspian basin

2020 ◽  
pp. 4-15
Author(s):  
M.F. Tagiyev ◽  
◽  
I.N. Askerov ◽  
◽  
◽  
...  
Keyword(s):  
Sedimentary Cover ◽  
Geochemical Data ◽  
Caspian Basin ◽  
Hydrocarbon Generation ◽  
The South ◽  
South Caspian Basin ◽  
Hydrocarbon Migration ◽  
Upward Migration ◽  
Modelling Studies ◽  
Hydrocarbon Charge

Based on pyrolysis data an overview is given on the generative potential and maturity of individual stratigraphic units in the South Caspian sedimentary cover. Furthermore, the pyrolysis analyses indicate that the Lower Pliocene Productive Series being immature itself is likely to have received hydrocarbon charge from the underlying older strata. The present state of the art in studying hydrocarbon migration and the "source-accumulation" type relationship between source sediments and reservoired oils in the South Caspian basin are touched upon. The views of and geochemical arguments by different authors for charging the Lower Pliocene Productive Series reservoirs with hydrocarbons from the underlying Oligocene-Miocene source layers are presented. Quantitative aspects of hydrocarbon generation, fluid dynamics, and formation of anomalous temperature & pressure fields based on the results of basin modelling in Azerbaijan are considered. Based on geochemical data analysis and modelling studies, as well as honouring reports by other workers the importance and necessity of upward migration for hydrocarbon transfer from deep generation centers to reservoirs of the Productive Series are shown.

A novel exploration technique using the microbial fingerprint of shallow sediment to detect hydrocarbon microseepage and predict hydrocarbon charge — An Argentinian case study

2021 ◽  
pp. 1-79
Author(s):  
Alin G. Chitu ◽  
Mart H. A. A. Zijp ◽  
Jonathan Zwaan
Keyword(s):  
Machine Learning ◽  
Oil Field ◽  
Dna Fingerprint ◽  
Evolutionary Constraint ◽  
Technology Study ◽  
Gas Field ◽  
Hydrocarbon Microseepage ◽  
Hydrocarbon Charge ◽  
Abundance And Distribution

The fundamental assumption of many successful geochemical and geomicrobial technologies developed in the last 80 years is that hydrocarbons leak from subsurface accumulations vertically to the surface. Driven by buoyancy, the process involves sufficiently large volumes directly measurable or indirectly inferable from their surface expressions. Even when the additional hydrocarbons are not measurable, their presence slightly changes the environment, where complex microbial communities live, and acts as an evolutionary constraint on their development. Since the ecology of this ecosystem is very complicated, we propose to use the full-microbiome analysis of the shallow sediments samples instead of targeting a selected number of known species, and the use of machine learning for uncovering the meaningful correlations in these data. We achieve this by sequencing the microbial biomass and generating its “DNA fingerprint”, and by analyzing the abundance and distribution of the microbes over the dataset. The proposed technology uses machine learning as an accurate tool for determining the detailed interactions among the various microorganisms and their environment in the presence or absence of hydrocarbons, thus overcoming data complexity. In a proof-of-technology study, we have taken more than 1000 samples in the Neuqu謠Basin in Argentina over three distinct areas, namely, an oil field, a gas field, and a dry location outside the basin, and created several successful predictive models. A subset of randomly selected samples was kept outside of the training set and blinded by the client operator, providing the means for objectively validating the prediction performance of this methodology. Uncovering the blinded dataset after estimating the prospectivity revealed that most of these samples were correctly predicted. This very encouraging result shows that analyzing the microbial ecosystem in the shallow sediment can be an additional de-risking method for assessing hydrocarbon prospects and improving the Probability Of Success(POS) of a drilling campaign.

scholarly journals Impact of basin evolution, depositional environment, pore water evolution and diagenesis on reservoir-quality of Lower Paleozoic Haima Supergroup sandstones, Sultanate of Oman

GeoArabia ◽  
2004 ◽  
Vol 9 (4) ◽  
pp. 107-138
Author(s):  
Karl Ramseyer ◽  
Joachim E. Amthor ◽  
Christoph Spötl ◽  
Jos M.J. Terken ◽  
Albert Matter ◽  
...  
Keyword(s):  
Pore Water ◽  
Depositional Environment ◽  
Liquid Hydrocarbon ◽  
Gas Condensate ◽  
Reservoir Quality ◽  
Liquid Hydrocarbons ◽  
Eastern Flank ◽  
Oman Mountains ◽  
Hydrocarbon Charge

ABSTRACT Sandstones of the Early Paleozoic Miqrat Formation and Barik Sandstone Member (Haima Supergroup) are the most prolific gas/condensate containing units in the northern part of the Interior Oman Sedimentary Basin (IOSB). The reservoir-quality of these sandstones, buried to depths exceeding 5 km, is critically related to the depositional environment, burial-related diagenetic reactions, the timing of liquid hydrocarbon charge and the replacement of liquid hydrocarbon by gas/condensate. The depositional environment of the sandstones controls the net-sand distribution which results in poorer reservoir properties northwards parallel to the axis of the Ghaba Salt Basin. The sandy delta deposits of the Barik Sandstone Member have a complex diagenetic history, with early dolomite cementation, followed by compaction, chlorite formation, hydrocarbon charge, quartz and anhydrite precipitation and the formation of pore-filling and pore-lining bitumen. In the Miqrat Formation sandstone, which is comprised of inland sabkha deposits, similar authigenic minerals occur, but with higher abundances of dolomite and anhydrite, and less quartz cement. The deduced pore water evolution from deposition to recent, in both the Miqrat Formation and the Barik Sandstone Member, reflects an early addition of saline continental waters and hydrocarbon-burial related mineral reactions with the likely influx of lower-saline waters during the obduction of the Oman Mountains. Four structural provinces are recognized in the IOSB based on regional differences in the subsidence/uplift history: the Eastern Flank, the Ghaba and Fahud Salt Basins and the Mabrouk-Makarem High. In the Fahud Salt Basin, biodegradation of an early oil charge during Late Paleozoic uplift resulted in reservoir-quality degradation by bitumen clogging of the pore space. On the Eastern Flank and the Mabrouk-Makarem High, however, the early oil bypassed the area. In contrast, post-Carboniferous liquid hydrocarbons were trapped in the Mabrouk-Makarem High, whereas on the Eastern Flank surface water infiltration and loss of hydrocarbons or biodegradation to pore occluding bitumen occurred. In the Ghaba Salt Basin, post-Carboniferous hydrocarbon charge induced a redox reaction to form porosity/permeability preserving chlorite in the reservoirs. The liquid hydrocarbons were replaced since the obduction of the Oman Mountains by gas/condensate which prevented the deep parts (>5,000 m) of the Ghaba Salt Basin from pore occluding pyrobitumen and thus deterioration of the reservoir quality.

Thermal and hydrocarbon-charge history and the relationship between diagenesis and reservoir connectivity: Venture field, offshore Nova Scotia, eastern Canada1Geological Survey of Canada Contribution 20100418.

2011 ◽  
Vol 48 (9) ◽  
pp. 1293-1306 ◽  
Author(s):  
Atika Karim ◽  
Georgia Pe-Piper ◽  
David J.W. Piper ◽  
Jacob J. Hanley
Keyword(s):  
Nova Scotia ◽  
Fluid Inclusions ◽  
Upper Jurassic ◽  
Gas Reservoirs ◽  
Carbonate Cements ◽  
Migration History ◽  
Carbonate Cementation ◽  
Homogenization Temperatures ◽  
Hydrocarbon Charge ◽  
Reservoir Connectivity

Fluid inclusions in diagenetic cements in Upper Jurassic – Lower Cretaceous sandstones offshore Nova Scotia provide constraints on the fluid migration history in gas reservoirs of the Scotian basin. Diagenetic minerals from six wells in the Venture field were analysed by optical petrography, scanning electron microscopy (SEM), and electron microprobe. A total of 122 primary and secondary fluid inclusions were analysed from different cements. Primary aqueous inclusions in quartz overgrowths have homogenization temperatures (Th) of 111.8 ± 7.1 °C (1σ) and in later carbonate cements 126.5 ± 2.1 °C; inclusions in both cements are highly saline (16–26.1 wt.% NaCl equivalent). Secondary aqueous and hydrocarbon-bearing inclusion trails crosscutting silica cement and detrital quartz have Th of 121.6 ± 13.6 °C and low salinities (8.7 ± 6.0 wt.%). Secondary carbonic inclusions have CO2 melting temperatures (–56.6 ± 0.1 °C) and Th (–9.3 ± 0.8 °C) indicating a high-density carbonic phase. Late carbonate cements in the same sandstone units vary in chemical composition in different wells, and connected reservoirs show similar late carbonate assemblages, suggesting that the late carbonate cementation may be partly controlled by the reservoir fill and spill sequence. Silica and late carbonate cementation involved highly saline fluid flow, likely at about ∼135 Ma. Hydrocarbon migration postdated silica cementation and was associated with secondary fracturing, suggesting that it corresponded to the onset of overpressure.

A Hydrocarbon Charge Model of the Hibernia Drainage Area, Jeanne d'Arc Basin, Offshore Newfoundland

1994 ◽  
Vol 12 (4) ◽  
pp. 295-323
Author(s):  
Mark Williamson ◽  
Kevin Coflin ◽  
Scott King ◽  
Kevin Desroches ◽  
Phil Moir ◽  
...  
Keyword(s):  
Oil Field ◽  
Drainage Area ◽  
Secondary Migration ◽  
Jeanne D'arc Basin ◽  
The North ◽  
Charge Model ◽  
Jeanne D'arc ◽  
Hydrocarbon Charge ◽  
Volume Estimates ◽  
Migration Loss

An integration of map based and geological/geochemical modelling methodologies has enabled us to image the burial, subsidence, thermal and organic maturation histories of an area which, given its present and past structural geometry, drains into the Hibernia Oil Field. Our models indicate that the deeper parts of the Hibernia Drainage Area (HDA) contributed significant volumes of hydrocarbons, as early as 80–100 Ma, to the Hibernia structural culmination. The shallower portion of the HDA, such as the area vertically below pooled petroleum at Hibernia, has only been contributing hydrocarbons during the last 30–40 Ma. Translation of the modelled maturation history into volumetric estimates of generated, expelled and migrated oil within the area is accomplished assuming a 20% saturation threshold prior to hydrocarbon flow from the source to the reservoir/carrier system. Secondary Migration loss is estimated through assuming a reservoir/carrier-wide residual saturation of 2%. Our volume estimates suggest that the defined HDA was unable to provide sufficient charge volumes to fill the Hibernia structure and that additional charge must have been available from a drainage area to the north across the Nautilus fault. Extrapolation of HDA volumes throughout specifically defined play areas and the broader Jeanne d'Arc Basin suggests that, after accounting for secondary migration loss and assuming 30% recovery efficiency, some 2,015 106m3 (12,650 Mmbbls) of oil remains to be discovered. Our models do not account for losses due to biodegradation processes. Although this is not thought to be significant within the HDA, it will reduce basin-wide resources estimates and requires further study.

Hydrothermal dolomitization in the Lower Silurian Sayabec Formation in northern Gaspé – Matapédia (Québec): constraint on timing of porosity and regional significance for hydrocarbon reservoirs

2004 ◽  
Vol 52 (3) ◽  
pp. 256-269 ◽  
Author(s):  
Denis Lavoie ◽  
Claude Morin
Keyword(s):  
High Temperature ◽  
Stable Isotope ◽  
Isotope Ratios ◽  
Stable Isotope Ratios ◽  
Lower Silurian ◽  
The Matrix ◽  
Saddle Dolomite ◽  
Northern Edge ◽  
Calcite Cement ◽  
Hydrocarbon Charge

Abstract The study of dolostone of the Lower Silurian Sayabec Formation of the Lac Matapédia syncline, at the western end of the Gaspé Peninsula, sheds new light on porosity development and reservoir potential of the area. The dolomitized section is close to the Shickshock Sud Fault that cuts the southern limb of the syncline. The dolostone occurs either as a highly brecciated unit or as stratiform replacement of peritidal carbonates at the base of the formation. Residual bitumen is seen in the breccia as well as filling of small secondary vugs and fractures within the stratiform dolostone. The dolostone consists predominantly of replacive matrix dolomite; petrography and oxygen and carbon stable isotope ratios (δ18OVPDB = −6.3 to −7.8‰ and δ13CVPDB = 1.2 to 3.3‰) of the matrix dolomite indicate early burial formation with later recrystallization in the presence of high temperature fluids. Saddle dolomite is found as a pore-filling cement in secondary dissolution pores and fractures. Oxygen stable isotope ratios of the saddle dolomite cement (δ18OVPDB = −14.5 and −15.3‰) indicate precipitation at high temperature. Dull luminescent burial calcite cement follows saddle dolomite. Later dissolution is locally apparent in carbonates as scalloped surfaces covered by finely laminated, bright-very dull luminescent calcites. Petrography and stable isotope ratios of the calcite (δ18OVPDB = −10.1 and −11.2‰ and δ13CVPDB = −2.3 and −6.9‰) suggest precipitation from meteoric waters. Meteoric dissolution and luminescent-zoned calcite cements are related to a Pridolian sea level lowstand. This event provides a first age constraint on the timing of the hydrothermal dolomitization and hydrocarbon charge of the Sayabec Formation along the northern edge of the Gaspé Belt. The Shickshock Sud Fault channelled the hydrothermal fluids, which dolomitized the Sayabec Formation shortly after initial burial. A recent regional seismic program showed compressive structures (duplexes, backthrust, triangle zone) in the Sayabec Formation inferred to have occurred in latest Silurian–Early Devonian that generated structural traps superimposed on the stratigraphic (shaly facies) and diagenetic (tight non-dolomitized limestone) seals. Seismic anomalies (“flat spots”) in the Lower Silurian section in eastern Quebec suggest the presence of hydrocarbon-filled reservoirs.

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