Grosmont Formation Research Articles

Geological controls on the heterogeneous hydrocarbon compositions of the biodegraded Grosmont Formation bitumen, Western Canada Sedimentary Basin

The hydrocarbon composition of the Grosmont Formation bitumen was investigated in 51 core samples by gas chromatography–mass spectrometry (GC–MS). The bitumen composition is highly variable and is heavily to severely biodegraded. Molecular ratios based on biodegradation-resistant compounds are highly uniform laterally and vertically, even across shale barriers indicating the bitumens are genetically related. Biodegradation-resistant biomarker maturity parameters suggests the bitumen was likely sourced during the early oil window stage of petroleum generation. Biomarkers responding to biodegradation display strong lateral and vertical variations in composition with geochemical profiles based on concentration data, displaying dramatic offsets when shales are present indicating the reservoir units are compartmentalised. Considering the relationship between 25-norhopanes and hopanes, the hydrocarbon composition data indicate progressive hopane degradation, both with concomitant formation of 25-norhopanes and hopane degradation without the formation of 25-norhopanes. In wells 07-08-085-18W4 and 10-12-093-24W4, the degradation of hopanes occurs in Upper Grosmont unit 3 (UG3) without the formation of 25-norhopanes (unless 25-norhopanes have been synchronously consumed), whereas in unit UG2, hopane degradation occurs with the concomitant formation of the 25-norhopanes. Therefore, the shale compartmentalizes the reservoir creating two isolated environments whereby the biogeochemical setting contributing to 25-norhopane formation is found in the UG2 unit, whereas it is absent or inactive in unit UG3. The degradation of the 22R epimer prior to the 22S epimer in the C31–C33 17α-hopanes was recognized in well 16-05-088-19W4, which indicates that the consortia of microbes more readily biodegraded the epimer having the biological conformation.

Pressure and temperature dependence of acoustic wave speeds in bitumen-saturated carbonates: Implications for seismic monitoring of the Grosmont Formation

Recent time-lapse seismic observations in carbonate reservoirs subject to steam-assisted enhanced oil recovery display substantial changes in seismic reflectivity due to the combined effects of saturation, pressure, and temperature. Understanding these field seismic observations requires knowledge of the effects on the seismic wave speeds in bitumen-saturated carbonates. We have conducted ultrasonic measurements of P- and S-wave velocities in bitumen-saturated dolomite taken from the Grosmont Formation in northern Alberta. Wave speeds are measured under a variety of conditions of constant pore pressure, constant effective pressure, and with varying temperature to map the various controlling factors. The temperature-dependent declines of 12% and 9% for the P- and S-wave speeds, respectively, with temperatures from 10°C to 102°C are most notable. Unlike oil sands, at times, the dolomite retains its structure upon removal of the bitumen allowing for measurement of the dry and water-saturated frame properties and their subsequent use in substitutional modeling. None of the standard bounding, inclusion, or Biot-Gassmann family models adequately describe the observations in the heated sample. The deviations may be in part due to the inability of these models to properly incorporate the complex bitumen non-Newtonian rheology including a bulk viscosity.

Analysis on the SAGD Simulation Using Characteristic Variable of Fracture System in Fractured Carbonate Reservoirs

The OOIP (original oil in-place) of bitumen in fractured carbonate reservoir of Grosmont, Canada is estimated at about 406.5 billion barrels. The Grosmont reservoir is characterized as various matrix sizes due to heterogeneity in fracture density. SAGD simulations for the Grosmont Formation have been based on the dual porosity and dual permeability model. In this study, characteristic variables for fracture system are considered to reflect the mechanism in fracture due to steam injection. The result shows that the characteristic variables play important role in dual porosity model, while trivial in dual permeability model. The effect of the characteristic variables for fracture system has been investigated in terms of the optimal preheating period, recovery factor, and cSOR.

A Study on the Formation Environment of Dolomite within the Devonian Grosmont Formation, Alberta, Canada

A Study on the Formation Environment of Dolomite within the Devonian Grosmont Formation, Alberta, Canada

Reservoir geology of the Grosmont Formation Bitumen Steam Pilot, Saleski, Alberta

Abstract The Grosmont Formation, with an estimated resource of 64.5 billion m3 (406 billion bbl), is one of the largest bitumen deposits in the world. The Grosmont Formation contains four stacked carbonate units. The uppermost two, the Grosmont C and D, contain the bulk of the Grosmont bitumen resource. The Grosmont C reservoir interval is 20 m thick and consists mainly of vuggy dolomite with an average porosity of 18.6%. The overlying 32 m thick Grosmont D has an average porosity of 24.3% and its main reservoir facies is dolomite breccia. Bitumen and water saturations are variable throughout the reservoir and require either core analysis or exotic logging tools such as nuclear magnetic resonance logging for accurate determination. One outcome of the improved understanding of bitumen saturations within the Grosmont reservoirs was the identification of a lean bitumen zone within the Grosmont D. Through the use of radioactive tracer logs, it was determined that this zone is a major drilling fluids thief zone. Laricina Energy Ltd. and Osum Corp. are conducting a cyclic steam assisted gravity drainage (SAGD) pilot at Section 26 Twp 85 Rge 19W4M using horizontal wells in both the Grosmont C and D. The pilot has produced 79 500 m3 (500 000 bbl) of bitumen up to February, 2015.

Organization, flow impact and modeling of natural fracture networks in a karstified carbonate bitumen reservoir: an example in the Grosmont Formation of the Athabasca Saleski leases, Alberta, Canada

Abstract The Grosmont Formation in Alberta contains one of the largest hydrocarbon accumulations of a carbonate reservoir in the world. It is also a highly fractured reservoir, where natural fracture networks have a key bearing on production and final recovery. The present fracture study focused on the Grosmont C and D units of the Saleski leases, where a steam injection pilot for the Grosmont was initiated in 2010 by Laricina Energy Ltd. and its partner, Osum Oil Sands Corp. This study aimed at characterizing the types, scales and organization of fractures in the reservoir units in order to build a representative fracture model and derive corresponding fracture properties to be used in dual porosity dynamic simulations. Detailed core and borehole image analyses revealed that fracturing in the Grosmont C and D units is organized into four sets of metre-scale joints and isotropic, centimetre-scale dissolution-related cracks. The joint density is controlled by facies. Dynamic data analysis revealed a link between mud losses, rock dissolution and facies types, especially in the Middle D unit. It also emphasized the fracture contribution to overall reservoir permeability. All of these findings were integrated to build a multiscale fracture model which, once dynamically calibrated, allowed computing fracture porosity, permeability tensor and matrix block sizes. These outputs are critical for thermal dual porosity dynamic simulations.

Comparison of McMurray Formation (Lower Cretaceous) and Grosmont Formation (Upper Devonian) bitumen reservoirs with some speculations, from a geological perspective, on the future of Canadian thermal recovery

Abstract Using the data from over 8000 wells augmented by seismic and thermal response information, a comparison of McMurray Formation (Cretaceous) and Grosmont C member (Devonian) thermal recovery reservoirs of northeastern Alberta is provided along with a discussion of reservoir performance to date. Fluvial-estuarine McMurray Formation reservoirs perform best where bitumen-charged homogeneous lenticular sandstones at least 20 metres thick are found. These deposits are relatively rare as the formation is characterized by endemic heterogeneity mainly in the form of inclined heterolithic stratification (IHS). Most of the best McMurray steam-assisted gravity drainage (SAGD) reservoirs appear to be currently on-line and produce approximately 113 000 m3/day of bitumen from fourteen projects. Platform carbonate Grosmont C successions are blanket deposits 32–35 metres thick, with bitumen columns typically 15–24 metres thick, and are characterized by consistent reservoir properties facilitated by pervasive multi-scale fracturing. Although no reserves have yet to be assigned to Alberta’s bitumen-bearing carbonates by the province, recent pilot results derived from cyclic steam stimulation (CSS) operations suggest that Grosmont C reservoir performance could ultimately prove to be competitive with superior McMurray SAGD reservoirs. Under current technological and economic conditions, McMurray SAGD reservoirs appear incapable of providing the 15.9 billion m3 of in-situ bitumen reserves (59% of Canada’s total oil reserves) ascribed to this formation by the province of Alberta as only circa 6 billion m3 of oil-in place appears to reside within optimal reservoirs (i.e. those reservoirs at least 20 metres thick with average porosity and oil saturation values of 33% and 80%, respectively). Barring future technological breakthroughs and, or, economic improvements, future commercial development of both the Grosmont C and other carbonate reservoirs might be needed to make up for some of the potential reserve shortfall associated with McMurray Formation SAGD reservoirs.

Bitumen Recovery from Carbonates by a Modified SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoir) Method Using Wettability Alteration Chemicals

This study investigates the applicability of the modified version of the previously proposed SOS-FR (steam-over-solvent injection in fractured reservoir) method to recover bitumen from the Grosmont formation in Canada. Three phases were applied on a total of 13 preserved core samples. In Phase 1, the cores taken from three different parts of the Grosmont formation were soaked in a liquid solvent (heptane or distillate) at ambient conditions. The objective of the first phase was to reduce the viscosity of the bitumen in preparation for the second phase which is wettability alteration. In Phase 2, we soaked the samples in water with chemicals. Wettability modifiers tested include high pH solution, cationic surfactants, and ionic liquids because the screening process indicated they are the most useful wettability alteration chemicals for oil-wet carbonates. One of the key benefits of the ionic liquids is that they are environmentally friendly as they are chemically stable with low level of toxicity and flamm...

Geochemical characterization of an organic-rich carbonate from the Grosmont Formation, Alberta, Canada

The Grosmont Formation is a massive, organic-rich carbonate deposit that subdivides into upper (UG) and lower (LG) units. Geochemical analyses of Grosmont carbonate rocks collected from wells 10-12-93-24W4 and 11-33-94-22W4 allowed us to differentiate the depositional and diagenetic conditions for these two units. The UG unit subdivides into three subunits (UG1–UG3) and consists of fine- to coarse-crystalline and subhedral dolomite. The LG unit consists of dolomitic limestone and calcareous dolostone with medium- to coarse-crystalline, euhedral to subhedral dolomite and calcite. These units also include small amounts of quartz, illite, pyrite, K-feldspar and other trace minerals. Petrographic and geochemical analyses indicate that the LG unit formed under influence of clastic sediment input. Isotopic ratios for UG dolomites suggest precipitation within a near surface environment under evaporitic/ hypersaline conditions. By contrast, the LG dolomite may have formed in a diagenetic environment at salinities lower than those inferred for UG samples, according to observed isotopic ratios. Both UG and LG carbonates exhibit 87Sr/86Sr ratios (0.7082 to 0.7086) and δ18O values (−4.03 to −6.09‰ PDB) that are consistent with formation from Devonian seawater at temperatures ranging from 44 °C to 57 °C.

A random Cantor set as a measure of the statistical homogeneity of fractured rock masses

This study addresses the applicability of the exponent of a power-law scaling model, as an index of the statistical homogeneity of fractured rock masses. We systematically examine the capability of a random Cantor set, Dc, to quantify the combined effect of fracture density and size distribution on fracture networks. Total 129 two-dimensional fracture configurations were generated, based on different combinations of fracture size distribution and fracture density. The Dc for each generated fracture network system was calculated using the random Cantor dust method. We found that the standard deviation of trace length has no effect on the calculated Dc, and the estimated Dc increases with the total density and/or mean trace length. To explore the field applicability of this study, we investigated the statistical homogeneity of a fractured rock mass of the Upper Devonian Grosmont Formation in Alberta, Canada. The results clearly show that the methodologies given in this study are capable of determining the statistical homogeneity of fractured rock masses.

Oil-Recovery Mechanisms in Bitumen-Bearing Carbonate Rocks

Laboratory testing was conducted over a 6-year period to aid recovery of oil in the Grosmont formation’s bitumen-bearing carbonate reservoirs, with the intent of providing billions of barrels of oil for the Province of Alberta. Through experiments measuring oil recovery from varying water and steam processes, it was found that wet steam provides the most efficient displacement medium. The oil recovery shows a significant impact of thermal expansion and gas drive, which can lead to significant oil displacements at early times, specifically where the localized open-porosity network fractures is extensive. Bitumen recovery from carbonate systems is achieved through a combination of thermal expansion, gas drive, gravity drainage of oil out of connected open porosity, and imbibition of water into the rock matrix.

Paleokarst in the Grosmont Formation and reservoir implications, Saleski, Alberta, Canada

We delineated a bitumen-rich paleokarsted carbonate reservoir of the Upper Devonian (Frasnian) Grosmont Formation with a high-resolution 3D seismic survey tied to core and petrophysical log data from 35 wells within a [Formula: see text] study area in northern Alberta, Canada. There were two laterally continuous karst facies: a solution-enhanced vuggy dolostone that resulted from the carbonate dissolution of body fossils and a stratiform breccia that resulted from the dissolution of interbedded evaporites. Three laterally discontinuous karst facies were identified: sinkhole fills, collapsed paleocaves, and solution valley fills. We measured 368 subcircular features (sinkholes and collapsed paleocaves) having a median circle-equivalent diameter of 69 m and representing 5.5% of the total study area. Sinkhole fills include Cretaceous-aged sandstone, mudstone, and coal. Collapsed paleocaves were filled with matrix-supported breccia that had clasts of disoriented blocks of dolomite and a matrix of disaggregated dolomite and Cretaceous-aged mudstone. The paleocaves and sinkholes formed in the solution-enhanced karst facies of the Grosmont C at the interface of an interpreted ancient vadose-phreatic mixing zone. The marine deepwater deposition of the Clearwater Formation during the Albian filled the depressions created by the mechanical collapse of the paleocaves and provided a seal for thermal operations. The fracture density inferred from seismic amplitude variation with angle and azimuth analysis and corroborated by well data showed that fractures are ubiquitous and were enhanced during meteoric karst. The high-vertical permeability resulting from solution-enhanced fractures, the laterally predictable flow units, and a competent seal make this an ideal reservoir for thermal bitumen recovery.

Simulation Study of the SAGD for the Carbonate Reservoir Model Incorporating Fracture Characteristics of Grosmont Formation, Canada

Simulation Study of the SAGD for the Carbonate Reservoir Model Incorporating Fracture Characteristics of Grosmont Formation, Canada

Thermal Recovery of Bitumen From the Grosmont Carbonate Formation - Part 1: The Saleski Pilot

Summary The Grosmont formation, a carbonate reservoir in Alberta, Canada, has 400 billion bbl of bitumen resource, which is currently not commercially exploited. The carbonate reservoir is karstified by groundwater and tectonically fractured, resulting in three classes of porosity: matrix, vugs, and fractures. The viscosity of bitumen is lowered by four to six orders of magnitude when heated by steam. Since December 2010, the Saleski pilot project evaluated steam-injection-recovery processes by use of four well pairs, two each in the Grosmont C and Grosmont D units. For the first year of the pilot, two well pairs were operated with continuous injection and production similar to successful steam-assisted-gravity drainage(SAGD) projects in Alberta oil sands. Reservoir observations of steam/oil ratio (SOR) and calendar-day oil rate (CDOR) indicate recovery by gravity drainage is viable, although operating practices from conventional SAGD must be modified for the Grosmont formation. The decision to evaluate cyclic injection and production from single wells was made in early 2012, although it was recognized that cyclic operations created new challenges for the facility (which was built for SAGD operations) and artificial lift. The pilot data indicate that the drilling conditions (balanced vs. overbalanced), completions (openhole vs. slotted liner), and acid treatments of the wells have a significant impact on the individual-well performance. Injectivity into the Grosmont reservoir is high, even into a cold reservoir, because of the existing fracture system. Injection pressures stayed less than 40% of the estimated pore pressure required to lift the overburden. 4D-seismic results indicate that the injection conformance along the well axis is close to 100% and that the heated area is laterally contained around the well. Productivity is comparable to oil-sands project performance. The decline of oil rate is not only dependent on pressure but also on temperature. For cyclic operations, a CDOR of 43 m3/d (for a 450-m-long well) and an SOR of 3.4 were achieved, demonstrating that with sufficient scale, a commercial project can be established successfully. The pilot has satisfactorily derisked the Grosmont reservoir at Saleski. While cyclic operations have demonstrated economic performance, continuous injection and production similar to SAGD remains an alternative recovery strategy beyond startup in the later depletion stage. Successful future developments will advance the optimization of drilling, completion, artificial-lift, and plant capacity issues, while the reservoir itself has demonstrated its production capacity.

Thermal Recovery of Bitumen From the Grosmont Carbonate Formation—Part 2: Pilot Interpretation and Development Strategy

Summary Bitumen production from the Grosmont formation is enabled by bitumen-viscosity reduction caused by heating with steam, and is driven by three processes: thermal expansion, gravity drainage, and spontaneous imbibition. Gravity drainage is the dominant recovery mechanism. Maintaining a balance of injected and produced fluid is indicative of good performance. The projected steam/oil ratio (SOR) for the carbonate Grosmont formation is comparable to that of the clastic Clearwater formation; the impact of lower porosity is compensated by lower water saturation. On the basis of the experience from the pilot project, a followup development of the Grosmont formation relies on cyclic operation of injection and production. Saleski Phase 1, approved by the Alberta Energy Regulator, is designed for 1700-m3/d oil capacity from the Grosmont formation. For the first time, probable undeveloped reserves have been assigned to a fractured-carbonate bitumen reservoir. The cyclic-to-continuous steam-assisted-gravity-drainage drainage (C2C-SAGD) concept, where initial cyclic operation of individual wells is converted into continuous injection and production with well pairs as the reservoir depletion matures, intends to maximize recovery in future exploitation projects.

Detailed topography of the Devonian Grosmont Formation surface from legacy high-resolution seismic profiles, northeast Alberta

The Devonian Grosmont Formation in northeastern Alberta, Canada, is the world’s largest accumulation of heavy oil in carbonate rock with estimated bitumen in place of [Formula: see text]. Much of the reservoir unconformably subcrops beneath Cretaceous sediments. This is an eroded surface modified by kartstification known as the Sub-Mannville Unconformity (SMU). We studied the reanalysis and integration of legacy seismic data sets obtained in the mid-1980s to investigate the structure of this surface. Standard data processing was carried out supplemented by some more modern approaches to noise reduction. The interpretation of these reprocessed data resulted in some key structural maps above and below the SMU. These seismic maps revealed substantially more detail than those constructed solely on the basis of well-log data; in fact, the use of only well-log information would likely result in erroneous interpretations. Although features smaller than about 40 m in radius cannot be easily discerned at the SMU due to wavefield and data sampling limits, the data did reveal the existence of a roughly east–west-trending ridge-valley system. A more minor northeast–southwest-trending linear valley also was apparent. These observations are all consistent with the model of a karsted/eroded carbonate surface. Comparison of the maps for the differing horizons further suggested that deeper horizons may influence the structure of the SMU and even the overlying Mesozoic formations. This suggested that some displacements due to karst cavity collapse or minor faulting within the Grosmont occurred during or after deposition of the younger Mesozoic sediments on top of the Grosmont surface.

Bitumen Recovery by the Steam-Over-Solvent Injection in Fractured Reservoirs (SOS-FR) Method: An Experimental Study on Grosmont Carbonates

We adapted the previously introduced SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoirs) method and conducted 12 experiments using preserved core samples from the Grosmont formation. The method applied in this study is based on soaking rather than continuous injection. The samples were immersed in hot water (90 °C), first to mimic low-temperature presteaming to condition the reservoir for solvent injection. This was followed by a solvent soaking period under varying conditions (duration, solvent type, etc.). Heptane and the distillate obtained from a heavy oil upgrading facility were used as solvents. Finally, the core samples were soaked in hot water again. Oil recoveries varied between 40% and 90% OOIP, with a mean value of 68%. Asphaltene precipitation, as a percentage of original oil in place (OOIP), was measured between 6.5 wt % and 33 wt %. The oil recovery and asphaltene precipitation depended on the solvent type, the solvent exposure duration, the position of matrix rock (horizontal or vertical), and the duration and number of solvent/hot water cycles. Most importantly, the last phase (hot water immersion) yielded substantial recovery of solvent diffused into matrix oil by applying a temperature value close to the boiling point of the solvent. The solvent retrieval was extremely fast and varied between 62% and 82% of the solvent diffused into the core during solvent exposure. Experimental observations look promising for further applications, as indicated by the high recovery values. The important aspects are that the solvent from readily available distillates used for transportation of heavy oil are very responsive and the temperature requirement for final hot water injection applied to retrieve solvent was <100 °C. Solvent retrieval was extremely quick and reasonably high, which is more likely to make the process economical.

Towards the Development of Bitumen Carbonates: An Integrated Analysis of Grosmont Steam Pilots

The Grosmont Formation in Alberta, Canada is a highly fractured, karstified and vuggy bitumen-rich carbonate reservoir located west of and below the Athabasca oil sands deposit. The bitumen carbonate platform extends about 500 km in length and up to 150 km in width and contains an estimated 64.5 billion m<sup>3<sup/> (406.5 billion barrels) of oil. The Grosmont Formation is larger than the combined total of all other known carbonate bitumen deposits in the world. Here, we analyze early Grosmont steam pilots to improve the design of future pilots and commercial development of this massive bitumen deposit. In agreement with the conclusions of earlier analysis of these Grosmont pilots, they were reasonably successful considering the heterogeneous nature of the Grosmont Formation. Operational factors such as poor steam quality, non-optimized high injection pressures and completion issues appear to have heavily impacted recovery performances. Clearly, steam-based recovery operations have good potential for Grosmont, especially considering that it is mature commercial technology. Following an integrated analysis of early Grosmont pilots, we posit that Cyclic Steam Stimulation (CSS) using horizontal wells exhibits greater potential for the development of Grosmont carbonate, compared with Steam-Assisted Gravity Drainage technology (SAGD).

Finding Pathways to Produce Heavy Oil From Canadian Carbonates

Alberta Heavy Oil Nearly 2 million bbl of ultraheavy crude are produced each day from Canadian oil sands, but the notion of also producing bitumen from reservoirs made of carbonate rock can spark skeptical remarks. They are likely to say something like: “Carbonates are very different. In carbonates, it is just different,” said Daniel Yang, director of reservoir engineering at Laricina Energy, who has a different reading of the exploration history of formations that hold more than 400 billion bbl of the crude. Laricina has partnered with a second Calgary independent, Osum Oil Sands, to try to prove that bitumen can be commercially produced from the Grosmont formation, which holds 75% of the heavy crude known as bitumen in Alberta’s carbonates. The reality is the Grosmont is different. A pilot project by Laricina and Osum showed that the well design commonly used for oil sands is not a good fit in carbonates. But a mix of methods used for bitumen production worked well enough to convince the partners to plan a commercial test. that they plan to use for the first commercial development in the formation. The Laricina-Osum joint venture has filed for a permit to produce as much as 10,700 B/D from up to 32 wells, with first oil in 2015. Husky and Shell have also filed for permission to do pilot projects with the Alberta Energy Regulator, the agency formerly known as the Energy Resources Conservation Board (ERCB). “It is going like early development in major oil sands basins such as the Athabasca, where there were many field pilots,” said Eddy Isaacs, chief executive officer of Energy and Environment Solutions at Alberta Innovates, a provincial agency that funds research, including past carbonates work. But moving from wells producing oil in situ in the relatively consistent sandstones and unconsolidated sands to carbonates will require significant advances in production methods and simulation software. The Grosmont was born complicated. It was formed hundreds of millions of years ago from the hap-hazard deposition of marine life off a long shoreline, was chemically transformed into dolomite, followed by water flows that carved it up, widening the fractures and carving out so many holes in the rock that it created weak spots in a formation that has been lifted and crushed and filled with oil that degraded into some of the world’s heaviest crude.

Geochemical analyses on bituminous carbonate reservoir in Alberta, Canada: focusing on the GC/GC-MS results of bitumen

The geochemical study on bituminous carbonate reservoir in Alberta has been performed to document the organic geochemical characteristics of the Grosmont Formation using two drilling cores (SAL 03-34 and SAL 08-01), especially focusing on the GC and GC-MS analyses. The results of GC and GC-MS analyses for the extracted organic matter (EOM) showed that all samples have been severely undergone a biodegradation process. However, the GC-MS data have displayed a little variation among the samples, which may be due to degree/type of biodegradation and the type of microbial activity. Triterpane biomarkers are present in low amounts, and steranes in even lesser amounts. Source and maturity assessments from both biomarkers are limited due to the lack of peaks by advanced biodegradation. The demethylated hopanes, which are typical of biodegraded oils, are not seen in these samples but they are apparently not unusual for the Athabasca tar sands, probably due to the specific type of post-emplacement microbial activity. Triterpanes biomarkers illustrate that a highly anoxic hypersaline source environment has contributed to the original oils, at the same time having anoxic marine carbonate/marl character. There is also tenuous evidence for a post-Triassic source according to the tricyclic terpane ratios. The steranes similarly indicate a marine, possibly carbonate-influenced source. Some of the aromatic compounds could also indicate a marine and anoxic hypersaline sourcing. The available peak ratios and patterns of EOM by GC-MS suggest high maturity, and aromatic parameters infer condensate window level with a vitrinite reflectance equivalent range of ∼0.9–1.2%. This could explain the remaining relatively light n-alkanes in the saturated GC chromatograms.