Petroleum System Modeling Research Articles

Source rock kinetics and petroleum generation history of the Upper Ordovician calcareous shales of the Hudson Bay Basin and surrounding areas

The current understanding of the Paleozoic petroleum system in Hudson Bay Basin remains far from complete due in no small part to the uncertainty in locally-calibrated generation and migration models underpinned with reliable source rock kinetic data. To improve the petroleum systems model, four representative immature organic-rich calcareous shales of Late Ordovician age from onshore outcrops surrounding the Hudson Bay were analysed to characterize their source rock generation kinetics. To constrain uncertainty due to laboratory measurement errors in kinetic parameter estimation, six heating rates were used in the pyrolysis experiments for each sample, resulting in 24 kinetic datasets that reduce uncertainty from both source rock heterogeneity and inherited laboratory measurement errors. Under the assumed geological time and geothermal framework, application of the kinetic models resulted in internally consistent generation histories, suggesting that the source rock started to generate oil when temperature reached 100 °C. It is likely where the maximum burial depth excessed 3000 m, the source rocks were in oil generation window with kerogen transformation ratio varying in a range between 52 and 78%. The modeled source rock maturity range from the immature outcrop samples is supported by bulk rock geochemistry data from cuttings of the source rock interval in offshore wells with high S1 peaks, large humps on the left shoulder on S2 curves, typical feature of FID pyrograms in the oil window. Comparison of the kinetic behavior of the samples in this study with those of typical marine Type I, Type II and Type IIS source rocks under laboratory condition and the assumed geological time/temperature framework suggests that kerogen converts to oil in a lower temperature range than those typical normal marine Type II source rock. We attribute the moderate sulfur content (likely high sulfoxide/thiophene ratio) and presence of kerogen component groups that are more prone to cleavage at low temperature as the cause for low temperature onset of hydrocarbon generation.

Seismic integrated study for offshore deep- and thin-stratum characterization: A case study from the Enping sag within the Pearl River Mouth Basin

In the Enping 17 sag within the Pearl River Mouth Basin in the South China Sea, one wildcat well has been drilled to the Lower Paleogene Enping Formation (FM EP) and partially into the Wenchang Formation (FM WC) for deep formation hydrocarbon exploration. However, no commercial play was discovered. The reasons for this are clear if the petroleum systems modeling is examined. In FM EP, the main reason for failure is due to poor sealing. In FM WC, the failure is due to the lack of a good reservoir for hydrocarbon accumulation. Encountering a 9 m thick reservoir at a depth of 4650 m indicates that braided fluvial delta and lowstand turbidite sandstone may develop in FM WC. With the objective of establishing cap rock in FM EP and reservoir rock in FM WC, and in the absence of sufficient well data, an integrated framework for 3D seismic reservoir characterization of offshore deep and thin layers was developed. The workflow includes seismic data reprocessing, well-log-based rock-physics analysis, seismic structure interpretation, simultaneous amplitude variation with offset (AVO) inversion, 3D lithology prediction, and geologic integrated analysis. We present four key solutions to address four specific challenges in this case study: (1) the application of adaptive deghosting techniques to remove the source and streamer depth-related ghost notches in the seismic data bandwidth and the relative amplitude-preserved bandwidth extension technique to improve the seismic data resolution; (2) a practical rock-physics modeling approach to consider the formation overpressure for pseudoshear sonic log prediction; (3) interactive and synchronized workflow between prestack 3D AVO inversion and seismic processing to predict a 9 m thick layer in FM WC through more than 60 rounds of cyclic tests; and (4) cross validation between seismic qualitative attributes and quantitative inversion results to verify the lithology prediction result under the condition of insufficient well data.

Shale oil and gas resource evaluation through 3D basin and petroleum systems modelling: a case study from the East Midlands, onshore UK

Technological advances in horizontal drilling and hydraulic fracturing have led to a re-evaluation of the UK Carboniferous sequences for shale oil and gas potential. In the Gainsborough Trough, hemipelagic mudstones known collectively as the Bowland Shale were deposited during the Pendleian Substage (Late Mississippian). In this study the interpretation of heritage 2D and recent 3D seismic data allowed the reconstruction of the tectonic evolution of the basin, which was simulated in a 3D basin and petroleum systems model. The model enabled the first prediction of generated, adsorbed, retained and expelled hydrocarbon volumes. Between 8 and 26 Bbbl of STOIIP, and between 11 and 38 tcf of GIIP have been estimated to lie within the Bowland Shale in the Gainsborough Trough. However, at the present time, there is considerable uncertainty concerning these in-place volumes, and no tests have proven the recoverability of oil and gas from the Bowland Shale in this area. Importantly, the Bowland Shale has been modelled as a single homogeneous layer, and the in situ volume numbers need to be corrected for a net to gross factor, once the criteria required for the definition for net reservoir in this formation are better understood.

Geology and petroleum prospectivity of the Larne and Portpatrick basins, North Channel, offshore SW Scotland and Northern Ireland

The Larne and Portpatrick basins, located in the North Channel between SW Scotland and Northern Ireland, have been the target of a small programme of petroleum exploration activities since 1971. A total of five hydrocarbon exploration wells have been drilled within the two basins, although as of yet no commercial discoveries have been made. The presence of hydrocarbon shows alongside the discovery of two good-quality reservoir–seal couplets within Triassic and underlying Permian strata has encouraged exploration within the region. The focus of this study is to evaluate the geology and hydrocarbon prospectivity of the Portpatrick Basin and the offshore section of the Larne Basin. This is achieved through the use of seismic reflection data, and gravity and aeromagnetic data, alongside sedimentological, petrophysical and additional available datasets from both onshore and offshore wells, boreholes and previously published studies. The primary reservoir interval, the Lower–Middle Triassic Sherwood Sandstone Group ( c . 600–900 m gross thickness), is distributed across both basins and shows good to excellent porosity (10–25%) and permeability (10–1000 mD) within the Larne Basin. The Middle–Late Triassic Mercia Mudstone Group should provide an excellent top seal where present due to the presence of thick regionally extensive halite deposits, although differential erosion has removed this seal from the margins of the Larne and Portpatrick basins. The Carboniferous, which has been postulated to contain organic-rich source-rock horizons, as inferred from their presence in adjacent basins, has not yet been penetrated within the depocentre of either basin. There is, therefore, some degree of uncertainty regarding the quality and distribution of a potential source rock. The interpretation of seismic reflection profiles presented here, alongside the occurrence of hydrocarbon shows, indicates the presence of organic-rich pre-Permian sedimentary rocks within both basins. 1D petroleum system modelling of the Larne-2 borehole shows that the timing of hydrocarbon generation and migration within the basins is a significant risk, with many traps post-dating the primary hydrocarbon charge. Well-failure analysis has revealed that trap breach associated with kilometre-scale uplift events, and the drilling of wells off-structure due to a lack of good-quality subsurface data, have contributed to the lack of discoveries. While the Larne and Portpatrick basins have many elements required for a working petroleum system, along with supporting hydrocarbon shows, the high risks coupled with the small scale of potential discoveries makes the Portpatrick Basin and offshore section of the Larne Basin poorly prospective for oil and gas discovery. Thematic collection: This article is part of the Under-explored plays and frontier basins of the UK continental shelf collection available at: http://www.lyellcollection.org/cc/under-explored-plays-and-frontier-basins-of-the-uk-continental-shelf

Redefining the relationship between the oil company and its vendor

During 2016, BHP committed to produce a petroleum systems model for the complete Exmouth Sub-basin area; such a model would require knowledge of the sub-basin’s evolution through time and a uniquely qualified team to deliver within the agreed time frame. Existing seismic coverage rarely illuminated the deepest portion of the basin; however, through a collaboration with WesternGeco Multiclient, a basin-wide broad-band 3D seismic survey was acquired to underpin the new study to ensure its success. To facilitate this acquisition and the development of the petroleum systems model, BHP and WesternGeco Multiclient created a virtual world-wide team to combine their expertise of seismic acquisition and processing, seismic and potential field interpretation, geochemistry and basin modelling. Although the work was coordinated in Perth (WA, Australia), team members were located in Australia, Europe and the US, where particular specific expertise was located. Both companies made a commitment before the commencement of the project to have open exchange of data, interpretations and knowledge transfer, with one project coordinator. Although individual contributors were located in Australia, Europe and the US, monthly video or telephone coordination meetings combined with weekly meetings between individual specialists, as needed, allowed for the project to be completed to the highest technical quality within the scheduled time frame. The collaborative interpretation from this new seismic data and the resulting petroleum system model has created significant value for both companies, with insights benefiting the industry as a whole as a result of this redefined relationship between company and vendor.

Exploring for the Future—a new oil and gas frontier in northern Australia

Exploring for the Future (EFTF) is a four-year, AU$100.5 million initiative from the Australian Government conducted by Geoscience Australia in partnership with state and Northern Territory government agencies, CSIRO and universities to provide new geoscientific datasets for frontier regions. As part of this program, Geoscience Australia acquired two new seismic surveys that collectively extend across the South Nicholson Basin (L120 South Nicholson seismic line) and into the Beetaloo Sub-basin of the McArthur Basin (L212 Barkly seismic line). Interpretation of the seismic has resulted in the discovery of new basins that both contain a significant section of presumed Proterozoic strata. Integration of the seismic results with petroleum systems geochemistry, structural analyses, geochronology, rock properties and a petroleum systems model has expanded the knowledge of the region for energy exploration. These datasets are available through Geoscience Australia’s newly developed Data Discovery Portal: an online platform delivering digital geoscientific information, including seismic locations and cross-section images, and field site and well based sample data. Specifically for the EFTF energy project, a petroleum systems framework with supporting organic geochemical data has been built to access source rock, crude oil and natural gas datasets via interactive maps, graphs and analytical tools that enable the user to gain a better and faster understanding of a basin’s petroleum prospectivity.

Burial and thermal history of the Upper Silesian Coal Basin (Poland) constrained by maturity modelling – implications for coalification and natural gas generation

Maturity modelling was carried out using basin and petroleum system modelling (BPSM) software in the lithologic sections of 17 wells of the Upper Silesian Coal Basin (Poland). The best fit between calculated and measured vitrinite reflectance (VR), porosity and density data was obtained by applying a thickness of eroded sedimentary overburden from 1700 m in the east to 4500 m in the west and relatively low to moderate heat flow values during the maximum late Carboniferous burial. These heat flow values were in the range 50–71 mW/m 2 , most likely owing to rapid deposition of molasse sediment that led to a downward deflection of the isotherms. The upper Carboniferous strata were heated to temperatures in the range c. 90–170 °C, which is in accordance with the moderate to high levels of thermal maturity of these rocks (c. 0.6–1.7%VR). The coal rank pattern was reached before the Variscan tectonic inversion at the transition between the Carboniferous and the Permian (c. 300 Ma). This coalification level was not overprinted by any later thermal processes. The coalification resulted in the generation of natural gases. The upper Carboniferous strata are characterized by early to late phases of hydrocarbon generation. The kerogen transformation ratio (c. 5–75%TR) values vary across the basin. Most coals generated significant amounts of hydrocarbons, which reached over 80 mg of methane per gram of total organic carbon. Although most hydrocarbons generated most likely were lost during the intense post-Variscan exhumation, the hydrocarbon potential of the basin is still substantial.

Comprehensive basin-wide 3D petroleum systems modelling providing new insights into proven petroleum systems and remaining prospectivity in the Exmouth Sub-basin, Australia

The Exmouth Sub-basin is part of the Northern Carnarvon Basin, offshore north-west Australia, and has undergone a complex tectonic history. Hydrocarbon exploration resulted in the discovery of a variety of oil and gas accumulations; however, their distribution and charge history from different petroleum systems is still poorly understood due to limited knowledge of the deeper basin architecture. The basin-wide, long-offset, broadband 2017 Exmouth 3D multiclient seismic dataset allowed a seamless interpretation into this deeper section. This work revealed new insights on the tectono-stratigraphic evolution of the Exmouth Sub-basin. Mesozoic extension, that was restricted to the latest Triassic, was followed by a sag phase with homogeneous, shale-dominated deposition, resulting in source rock potential for the entire Jurassic section. These findings, together with potential field modelling, were integrated into this first basin-wide 3D petroleum system model to better constrain the thermal history and petroleum systems. The model improved our understanding of the complex charge history of hydrocarbon fields. It predicts that hydrocarbon expulsion from Late Jurassic source rocks continued into the Late Cretaceous, a period when the regional Early Cretaceous Muderong Formation was an efficient seal rock. This implies that, in addition to long-distance, sub-Muderong migration, vertical, short-distance migration may have contributed significant petroleum charge to the discovered accumulations in the southern Exmouth Sub-basin. The model also predicts additional prospective areas: fault-seal structures within Early Cretaceous intervals north of the Novara Arch, intra-formational Late Jurassic sandstones north of the current fields (with low biodegradation risk) and Triassic reservoirs along the basin margins and north of the Jurassic depocentre.

Одномерное моделирование нефтегазоносных систем (бассейновое моделирование) в разрезе скважины Толонского месторождения Республики Саха (Якутия)

Одномерное моделирование нефтегазоносных систем (бассейновое моделирование) в разрезе скважины Толонского месторождения Республики Саха (Якутия)

On the importance of rock thermal conductivity and heat flow density in basin and petroleum system modelling

AbstractBasin and petroleum systems are routinely modelled to provide qualitative and quantitative assessments of a hydrocarbon play. The importance of the rock thermal properties and heat flow density in thermal modelling the history of a basin are well‐known, but little attention is paid to assumptions of the thermal conductivity, present‐day heat flow density and thermal history of basins. Assumed values are often far from measured values when data are available to check parameters, and effective thermal conductivity models prescribed in many basin simulators require improvement. The reconstructed thermal history is often justified by a successful calibration to present‐day temperature and vitrinite reflectance data. However, a successful calibration does not guarantee that the reconstruction history is correct. In this paper, we describe the pitfalls in setting the thermal conductivity and heat flow density in basin models and the typical uncertainties in these parameters, and we estimate the consequences by means of a one‐dimensional model of the super‐deep Tyumen SG‐6 well area that benefits from large amounts of reliable input and calibration data. The results show that the entire approach to present‐day heat flow evaluations needs to be reassessed. Unreliable heat flow density data along with a lack of measurements of rock thermal properties of cores can undermine the quality of basin and petroleum system modelling.

New insights into the Exmouth Sub-basin from basin and petroleum system modelling

The Exmouth Sub-basin forms part of the intra-cratonic rift system of the Northern Carnarvon Basin, Australia. It has undergone a complex tectonic history with multiple phases of uplift, erosion, i...

Source rocks of the German Central Graben

Abstract Jurassic to Lower Cretaceous formations are the most important source rocks for hydrocarbons in the southern Central Graben area. Within the Dutch Central Graben, the Lower Jurassic Posidonia Shale Formation is the most prolific source for hydrocarbons, while the Upper Jurassic to Lowermost Cretaceous Bo Member of the Farsund Formation plays this role in the Danish Central Graben. Oil and gas discoveries in the Norwegian, Dutch and Danish part of the Central Graben proved a prolific petroleum system. Despite limited success of hydrocarbon exploration in the German part of the Central Graben, various indications suggest migration of gas out of active thermogenic source rocks that are closely related to potential shallow gas accumulations. These indications include the restricted location of the bright spots above the Jurassic graben system, the occurrence of gas chimneys underneath these accumulations and geochemical data from offshore The Netherlands, which support contribution of thermogenic gas. The purpose of this study is to assess the potential for generating thermogenic hydrocarbons from Upper Triassic to Lower Cretaceous formations. For this reason, prominent source rocks of the Southern North Sea, i.e. the Posidonia Shale Formation and the Upper Jurassic to Lower Cretaceous “Hot Shales” (namely Clay Deep Member offshore The Netherlands and Bo Member offshore Denmark), were mapped in detail. These and other potential formations from the Late Triassic to the Early Cretaceous are integrated into an existing petroleum system model of the Northern German North Sea, which was modified for the new requirements. The results showed that the main source rocks of the southern Central Graben, the Posidonia Shale Formation, and the Upper Jurassic – Lower Cretaceous “Hot Shales” are insignificant as sources for commercial hydrocarbon accumulations within the German Central Graben area. That is either due to marginal occurrence or to low maturity. However, Lower to Upper Jurassic formations such as marine claystones of the Aalburg Formation and the lower parts of the Kimmeridge Clay Formation, as well as coaly intervals of the Central Graben Subgroup, are likely to have generated, and still generate, hydrocarbons.

Evaluation of the Modified Cam Clay model in basin and petroleum system modeling (BPSM) loading conditions

Abstract Basin and Petroleum System Modeling (BPSM) simulates the evolution of sedimentary basins over geological time spans, a highly complex process in which the mechanical representation of rocks is of the utmost relevance. Through geomechanical analyses, it is possible to quantify properties of the porous media (mainly porosity), simulate the formation of seals and traps and understand the propagation of faults and fractures, as well as their roles in fluid flow, all of which can significantly influence the prediction of hydrocarbons accumulations. However, the traditional mechanical model applied in BPSM simulators is an empirical law developed by geophysicist Lawrence F. Athy in the 1930s, based on a series of simplifications about the mechanical problem that may restrict its application in scenarios where geological processes others than one-dimensional compaction are acting. Thus, a constitutive model that accounts for the influence of three-dimensional states of stress and strain on the mechanical behavior of geological materials may represent a more robust solution in BPSM analyses. In that context, this work evaluates the ability of an alternative representation (Modified Cam Clay Model) to reproduce the mechanical behavior of sedimentary rocks in the deposition and compaction processes observed in BPSM using simplified test cases and Athy's compaction curve as reference.

Future directions in basin and petroleum systems modeling: A survey of the community

In the last 30 yr, basin and petroleum system modeling (BPSM) has evolved into a large and diverse field encompassing a broad range of scientific disciplines. As BPSM is applied to an increasingly wide range of problems, what are, or should be, the future directions in the evolution of BPSM comes into question. To address this question, a survey was conducted at the AAPG Hedberg Research Conference on “The Future of Basin and Petroleum Systems Modeling,” held in Santa Barbara, California, April 3–8, 2016. To capture the full range of thoughts, participants were asked to list in priority order what they think are the three most important future directions in BPSM. The responses were collated into six general categories for analysis. The categorization process involved some qualitative judgements because some areas spanned several of the general areas. The results show that the most frequently cited directions are related to BPSM workflows, organizations, and processes. This category includes how modelers are used in an organization, how projects are executed, and how the results are interpreted and integrated. Migration modeling (primary and secondary) is the most frequently cited technical need. The results indicate that migration processes are not well understood and there are still substantial differences of thought about the processes involved and the best ways to model them. Some subjects, such as uncertainty and unconventionals, were mentioned in several of the general categories, whereas other subjects, such as increased functionality in the models, were only seldom mentioned.

2D petroleum system modeling to reduce exploration well deployment risks: a case study from the Pearl River Mouth Basin, South China sea

To overcome the limitations of traditional way of exploration well deployment, an innovative workflow was developed to focus on dynamic factors with 2D petroleum system modeling technology. It was applied in the Zhu1 depression of the Pearl River Mouth Basin, Southern China, helping geologists to improve their understanding of the dynamic elements such as the generation of the source rocks and migration pathways along faults. Simulation show that source and migration can be screened from six risk factors, “Source”,” Reservoir”,” Cap”,” Migration”, “Trap” and “Preservation”. More simulations focused on two of the factors for different geological scenarios, fault properties, such as active period, and source rock properties, such as thickness, total organic carbon, hydrogen index. faults are the main migration control as their active period matches the main oil migration time. Of them, those cut through source rock layers and have the same inclination as that of the source rock formation acted as good migration paths. Source rock properties not only control the amount of oil generated, but also influence the vertical and lateral migration distances. Drilling result proves clearly that this new workflow is valuable for studying geological uncertainties and reduce exploration ricks.

Burial History Reconstruction of the Appalachian Basin in Kentucky, West Virginia, Pennsylvania, and New York, Using 1D Petroleum System Models

Nine 1D burial history models were built across the Appalachian basin to reconstruct the burial, erosional, and thermal maturation histories of contained petroleum source rocks. Models were calibrated to measured downhole temperatures, and to vitrinite reflectance (% Ro) data for Devonian through Pennsylvanian source rocks. The highest levels of thermal maturity in petroleum source rocks are within and proximal to the Rome trough in the deep basin, which are also within the confluence of increased structural complexity and associated faulting, overpressured Devonian shales, and thick intervals of salt in the underlying Silurian Salina Group. Models incorporate minor erosion from 260 to 140 million years ago (Ma) that allows for extended burial and heating of underlying strata. Two modeled times of increased erosion, from 140 to 90 Ma and 23 to 5.3 Ma, are followed by lesser erosion from 5.3 Ma to Present. Absent strata are mainly Permian shales and sandstone; thickness of these removed layers increased from about 6200 ft (1890 m) west of the Rome trough to as much as 9650 ft (2940 m) within the trough. The onset of oil generation based on 0.6% Ro ranges from 387 to 306 Ma for the Utica Shale, and 359 to 282 Ma for Middle Devonian to basal Mississippian shales. The ~1.2% Ro onset of wet gas generation ranges from 360 to 281 Ma in the Utica Shale, and 298 to 150 Ma for Devonian to lowermost Mississippian shales.

Geochemical evaluation of oil and gas samples from the Upper Devonian and Mississippian reservoirs Southern Anadarko Basin Oklahoma and its implication for the Woodford Shale unconventional play

Abstract The Woodford Shale, Sycamore, and Goddard formations have become important liquid rich unconventional resource play targets. Most petroleum experts believe the mature Woodford Shale is responsible for much of the southern Anadarko conventional and unconventional petroleum production with notable exceptions. This paper will focus on the well head oil and gas samples from the South Central Oklahoma Oil Province (SCOOP) area Woodford Shale and the younger Mississippian reservoirs. The purpose of this paper is to characterize the SCOOP area unconventional resource play using the produced petroleum. Discrepancies between produced oil and gas geochemistry, rock maturity, and production characteristics presents an interesting conundrum. The produced volatile oils contain lower boiling point compounds (C6–C8) that indicate a high maturity product from the Woodford Shale source, whereas the high molecular weight fraction (C15+ biomarkers) suggests a middle mature product from the Woodford Shale source. The produced gas chemistry suggests a low to middle mature product using published gas plots. Lastly, the production Gas Oil Ratio (GOR) and well head fluid gravities are typical of a gas-condensate. There is no simple unified petroleum system process to explain all these observations. There could be a combination of factors resulting in this conundrum such as mixing of multiple charges from both local and off-structure sources, phase separation as a result of production, or well head sampling/storage issues. At present it may be difficult to fully explain the current results, however we do believe the geochemistry and production results demonstrate a significant off-structure contribution. A simple petroleum systems model based on source rock organic matter type and maturity does not always correctly predict production or ultimate recovery.

Petroleum system modelling and identification of promising oil and gas bearing objects in the eastern part of the Gulf of Suez, Egypt

Petroleum system modelling and identification of promising oil and gas bearing objects in the eastern part of the Gulf of Suez, Egypt

Identification of oil and gas bearing objects using geophysical data in the eastern part of the Gulf of Suez, Egypt

The airborne magnetic data is considered as one of the best methods to delineate the depth to basement layer. The airborne magnetic survey data obtained from the Egyptian Nuclear Materials Authority. Data is accurately processed, interpreted. Two-dimensional (2D) modeling was performed by GM-SYS, along one selected profile yielded from RTP map. In addition to that, three-dimensional (3D) Euler Deconvolution method was performed to delineate the depth to basement layer. Euler solutions were applied on RTP Grid by structural indexes 0, 1, 2, and 3 to select the best solution. The sedimentary succession of the study area is created using seismic data and well data. Petroleum system model was established to predict the locations of hydrocarbons within the study area. The results of PetroMod confirmed that the area is very promising for hydrocarbon aggregations, and also new hydrocarbon aggregations have been discovered.

Quantification of thermal conductivity uncertainty for basin modeling

Thermal conductivity is a major influencing factor on subsurface conductive heat transport and resulting temperature distribution, which in turn is a key parameter in basin modeling. Basin modeling studies commonly use representative literature values of thermal conductivity despite their impact on modeling results. We introduce a workflow for quantifying the effect of uncertain thermal conductivity on subsurface temperature distribution and thus on basin modeling results and test this workflow on a two-dimensional generic model from the Nordkapp Basin; a prior ensemble of possible models is conditioned according to Bayes’ theorem to incorporate prior knowledge of temperature data. This conditional probability yields a posterior ensemble of temperature fields with a significantly reduced standard deviation. To verify our approach, we use five characteristic scenarios from the posterior ensemble for transient petroleum systems modeling. How considering uncertain thermal conductivity affects variance in hydrocarbon generation is assessed by modeling corresponding vitrinite reflectances (Ro). Temperature uncertainty increases with depth. It also increases with increasing offset from the salt diapirs, which can be associated with a large lateral heat-flow component in the complex tectonic environment of the Nordkapp Basin. The introduced workflow can reduce temperature uncertainty significantly, especially in regions with high prior uncertainty. The Ro is very sensitive to changes in thermal conductivity because the onset depth of the gas window in the Nordkapp Basin may vary by up to 800 m (2600 ft) within the 95% confidence interval. This demonstrates the importance of quantification of the uncertainty in thermal conductivity on thermal basin modeling.