A practical petrophysical model for a source rock play: The Mancos Shale

2017 ◽  
Vol 5 (3) ◽  
pp. T423-T435
Author(s):  
Jesús M. Salazar ◽  
Ron J. M. Bonnie ◽  
William W. Clopine ◽  
G. Eric Michael
Keyword(s):  
Source Rock ◽  
Water Saturation ◽  
Clay Content ◽  
Source Rocks ◽  
Crushed Rock ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Niobrara Formation ◽  
Mancos Shale ◽  
Petrophysical Model

Recently, the focus in source rock exploration has moved from gas-rich to liquid-rich plays and warrants revisiting “bypassed” hydrocarbon charged source rocks, which were deemed uneconomic when first drilled. In North America’s oil fields, there are thousands of wells with different vintages of nuclear and electrical logs, yet these wells generally lack any advanced logs beyond the traditional triple combo. We have developed a workflow that uses a considerable amount of laboratory measurements made on crushed rock to upscale a petrophysical model based on a triple combo logging suite only. The model divides the field (laterally) in oil window and gas window fairways and (vertically) in petrophysical units. The remaining hydrocarbon generation potential is based on geochemical measurements, such as thermal maturity and total organic carbon content (TOC), from core and cuttings in the area. The petrophysical units reflect major geologic intervals with similar porosity and clay content. The workflow was sequentially built by correlating logs with core measurements, using TOC and maturity for organic matter, X-ray diffraction for mineralogy and grain density, porosity, and water saturation from fluids extraction, for volumetrics. The model is applied to the Mancos Shale (New Mexico, USA), a Cretaceous-age source rock, which includes the Niobrara Formation. The Mancos Shale has been penetrated in various fields while developing conventional sandstone reservoirs. The model is validated with measurements on a core recently acquired in the anticipated high-hydrocarbon-yield window. Petrophysical properties predicted from logs agree well with core measurements in blind tests, demonstrating the robustness of the model despite being based on a basic suite of logs and a simple deterministic approach. This model is now routinely used by the asset team as an automated workflow to generate fairway maps, locate sweet spots, and for landing lateral wells.

scholarly journals Source rock geochemistry of shale samples from Ege-1 and Ege-2 wells, Niger Delta, Nigeria

2020 ◽  
Author(s):  
S. L. Fadiya ◽  
S. A. Adekola ◽  
B. M. Oyebamiji ◽  
O. T. Akinsanpe
Keyword(s):  
Source Rock ◽  
Niger Delta ◽  
Source Rocks ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
Early Maturity ◽  
Type Iii ◽  
Niger Delta Basin ◽  
Rock Eval

AbstractSelected shale samples within the middle Miocene Agbada Formation of Ege-1 and Ege-2 wells, Niger Delta Basin, Nigeria, were evaluated using total organic carbon content (TOC) and Rock–Eval pyrolysis examination with the aim of determining their hydrocarbon potential. The results obtained reveal TOC values varying from 1.64 to 2.77 wt% with an average value of 2.29 wt% for Ege-1 well, while Ege-2 well TOC values ranged from 1.27 to 3.28 wt% (average of 2.27 wt%) values which both fall above the minimum threshold (0.5%) for hydrocarbon generation potential in the Niger Delta. Rock–Eval pyrolysis data revealed that the shale source rock samples from Ege-1 well are characterized by Type II–Type III kerogens which are thermally mature to generate oil or gas/oil. The Ege-2 well pyrolysis result showed that some of the ditch cutting samples are comprised of Type II (oil prone) and Type III (gas-prone kerogen) which are thermally immature to marginal maturity (Tmax 346–439 °C). This study concludes that the shale intercalations between reservoir sands of the Agbada Formation are good source rocks in early maturity and also must have contributed to the vast petroleum reserve in the Niger Delta Basin because of the subsidence of the basin.

scholarly journals Study on Geochemical Characteristics of tight sandstone gas accumulation in Linxing area

2020 ◽  
Vol 206 ◽  
pp. 01017
Author(s):  
Yangbing Li ◽  
Weiqiang Hu ◽  
Xin Chen ◽  
Litao Ma ◽  
Cheng Liu ◽  
...  
Keyword(s):  
Source Rock ◽  
Ordos Basin ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Light Hydrocarbons ◽  
Tight Sandstone ◽  
Source Type ◽  
Reservoir Type ◽  
Sandstone Reservoir ◽  
Main Component

Based on the comprehensive analysis of the characteristics of tight sandstone gas composition, carbon isotope, light hydrocarbons and source rocks in Linxing area of Ordos Basin, the reservoir-forming model of tight sandstone gas in this area is discussed. The study shows that methane is the main component of tight sandstone gas, with low contents of heavy hydrocarbons and non-hydrocarbons, mainly belonging to dry gas in the Upper Paleozoic in Linxing area. The values of δ13C1, δ13C2 and δ13C3 of natural gas are in the ranges of -45.6‰ ~ -32.9‰, -28.9‰ ~ -22.3‰ and -26.2‰~ -19.1‰, respectively. The carbon isotopic values of alkane gas show a general trend of positive carbon sequence. δ13C1 value is less than -30‰, with typical characteristics of organic genesis. There is a certain similarity in the composition characteristics of light hydrocarbons. The C7 series show the advantage of methylhexane, while the C5-7 series mainly shows the advantage of isoalkane. The tight sandstone gas in this area is mainly composed of mature coal-derived gas, containing a small amount of coal-derived gas and oil-type gas mixture. According to the mode of hydrocarbon generation, diffusion and migration of source rocks in Linxing area, the tight sandstone gas in the study area can be divided into three types of reservoir-forming assemblages: the upper reservoir type of the far-source type (upper Shihezi formation-shiqianfeng formation sandstone reservoir-forming away from source rocks), the upper reservoir type of the near-source type ( the Lower Shihezi formation sandstone reservoir-outside the source rock), and the self-storage type of the source type (Shanxi formation-Taiyuan formation source rock internal sand reservoir).

scholarly journals The Cambrian Henson Gletscher Formation: a mature to postmature hydrocarbon source rock sequence from North Greenland

1987 ◽  
Vol 133 ◽  
pp. 141-157
Author(s):  
F.G Christiansen ◽  
H Nøhr-Hansen ◽  
O Nykjær
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Source Rock ◽  
Reservoir Rocks ◽  
Potential Source ◽  
Potential Reservoir ◽  
Field Season ◽  
North Greenland

During the 1985 field season the Cambrian Henson Gletscher Formation in central North Greenland was studied in detail with the aim of evaluating its potential as a hydrocarbon source rock. The formation contains organic rich shale and carbonate mudstone which are considered to be potential source rocks. These are sedimentologically coupled with a sequence of sandstones and coarse carbonates which might be potential reservoir rocks or migration conduits. Most of the rocks exposed on the surface are, however, thermally mature to postrnature with respect to hydrocarbon generation, leaving only few chances of finding trapped oil in the subsurface of the area studied in detail.

scholarly journals GEOCHEMICAL AND GEOSTATISTICAL ASSESSMENT OF CRETACEOUS COALS AND SHALES IN SOME NIGERAIN SEDIMENTARY BASINS FOR THEIR HYDROCARBON PRONESS AND MATURITY LEVELS

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Linear Regression Analysis ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Good Source ◽  
Type Iii ◽  
Limit Value ◽  
The Impact

The Rock–Eval pyrolysis and LECO analysis for 9 shale and 12 coal samples, as well as, geostatistical analysis have been used to investigate source rock characteristics, correlation between the assessed parameters (QI, BI, S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Cretaceous Sokoto, Anambra Basins and Middle Benue Trough of northwestern, southeastern and northcentral Nigeria respectively. The geochemical results point that about 97% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales and Lafia/Obi coal are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt %, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 36.12 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 20.38 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson’s correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI. Keywords- Cretaceous, Geochemical, Statistical, Cluster; Factor analyses.

Liquid hydrocarbon characterization of the lacustrine Yanchang Formation, Ordos Basin, China: Organic-matter source variation and thermal maturity

2017 ◽  
Vol 5 (2) ◽  
pp. SF225-SF242 ◽  
Author(s):  
Xun Sun ◽  
Quansheng Liang ◽  
Chengfu Jiang ◽  
Daniel Enriquez ◽  
Tongwei Zhang ◽  
...  
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Ordos Basin ◽  
Depositional Environments ◽  
Source Rocks ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
Thermal Maturity ◽  
Yanchang Formation

Source-rock samples from the Upper Triassic Yanchang Formation in the Ordos Basin of China were geochemically characterized to determine variations in depositional environments, organic-matter (OM) source, and thermal maturity. Total organic carbon (TOC) content varies from 4 wt% to 10 wt% in the Chang 7, Chang 8, and Chang 9 members — the three OM-rich shale intervals. The Chang 7 has the highest TOC and hydrogen index values, and it is considered the best source rock in the formation. Geochemical evidence indicates that the main sources of OM in the Yanchang Formation are freshwater lacustrine phytoplanktons, aquatic macrophytes, aquatic organisms, and land plants deposited under a weakly reducing to suboxic depositional environment. The elevated [Formula: see text] sterane concentration and depleted [Formula: see text] values of OM in the middle of the Chang 7 may indicate the presence of freshwater cyanobacteria blooms that corresponds to a period of maximum lake expansion. The OM deposited in deeper parts of the lake is dominated by oil-prone type I or type II kerogen or a mixture of both. The OM deposited in shallower settings is characterized by increased terrestrial input with a mixture of types II and III kerogen. These source rocks are in the oil window, with maturity increasing with burial depth. The measured solid-bitumen reflectance and calculated vitrinite reflectance from the temperature at maximum release of hydrocarbons occurs during Rock-Eval pyrolysis ([Formula: see text]) and the methylphenanthrene index (MPI-1) chemical maturity parameters range from 0.8 to [Formula: see text]. Because the thermal labilities of OM are associated with the kerogen type, the required thermal stress for oil generation from types I and II mixed kerogen has a higher and narrower range of temperature for hydrocarbon generation than that of OM dominated by type II kerogen or types II and III mixed kerogen deposited in the prodelta and delta front.

The transformation effect of source rock-derived acidic fluid on carbonate reservoir from simulation experiments

2020 ◽  
Author(s):  
Qian Ding ◽  
Zhiliang He ◽  
Dongya Zhu
Keyword(s):  
Physical Properties ◽  
Source Rock ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Hydrocarbon Generation ◽  
High Quality ◽  
Simulation Experiments ◽  
Deep Layers

&lt;p&gt;Deep and ultra-deep carbonate reservoir is an important area of petroleum exploration. However, the prerequisite for predicting high quality deep ultra-deep carbonate reservoirs lays on the mechanism of carbonate dissolution/precipitation. It is optimal to perform hydrocarbon generation-dissolution simulation experiments to clarify if burial dissolution could improve the physical properties of carbonate reservoirs, while quantitatively and qualitatively describe the co-evolution process of source rock and carbonate reservoirs in deep layers. In this study, a series of experiments were conducted with the limestone from the Ordovician Yingshan Formation in the Tarim Basin, and the low maturity source rock from Yunnan Luquan, with a self-designed hydrocarbon generation-dissolution simulation equipment. The controlling factors accounted for the alteration of carbonate reservoirs and dissolution modification process by hydrocarbon cracking fluid under deep burial environments were investigated by petrographic and geochemical analytical methods. In the meantime, the transformation mechanism of surrounding rocks in carbonate reservoirs during hydrocarbon generation process of source rock was explored. The results showed that: in the burial stage, organic acid, CO&lt;sub&gt;2&lt;/sub&gt; and other acidic fluids associated with thermal evolution of deep source rocks could dissolve carbonate reservoirs, expand pore space, and improve porosity. Dissolution would decrease with the increasing burial depth. Whether the fluid could improve reservoir physical properties largely depends on calcium carbonate saturation, fluid velocity, water/rock ratio, original pore structure etc. This study could further contribute to the prediction of high-quality carbonate reservoirs in deep and ultra-deep layers.&lt;/p&gt;

scholarly journals 3D-Basin Modelling of the Lishui Sag: Research of Hydrocarbon Potential, Petroleum Generation and Migration

Energies ◽  
2019 ◽  
Vol 12 (4) ◽  
pp. 650 ◽  
Author(s):  
Jinliang Zhang ◽  
Jiaqi Guo ◽  
Jinshui Liu ◽  
Wenlong Shen ◽  
Na Li ◽  
...  
Keyword(s):  
Source Rock ◽  
Thermal Evolution ◽  
Vitrinite Reflectance ◽  
Three Dimensional ◽  
Source Rocks ◽  
Rock Properties ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Accumulation ◽  
Southeastern Part ◽  
Petroleum Generation

The Lishui Sag is located in the southeastern part of the Taibei Depression, in the East China Sea basin, where the sag is the major hydrocarbon accumulation zone. A three dimensional modelling approach was used to estimate the mass of petroleum generation and accumulated during the evolution of the basin. Calibration of the model, based on measured maturity (vitrinite reflectance) and borehole temperatures, took into consideration two main periods of erosion events: a late Cretaceous to early Paleocene event, and an Oligocene erosion event. The maturation histories of the main source rock formations were reconstructed and show that the peak maturities have been reached in the west central part of the basin. Our study included source rock analysis, measurement of fluid inclusion homogenization temperatures, and basin history modelling to define the source rock properties, the thermal evolution and hydrocarbon generation history, and possible hydrocarbon accumulation processes in the Lishui Sag. The study found that the main hydrocarbon source for the Lishui Sag are argillaceous source rocks in the Yueguifeng Formation. The hydrocarbon generation period lasted from 58 Ma to 32 Ma. The first period of hydrocarbon accumulation lasted from 51.8 Ma to 32 Ma, and the second period lasted from 23 Ma to the present. The accumulation zones mainly located in the structural high and lithologic-fault screened reservoir filling with the hydrocarbon migrated from the deep sag in the south west direction.

A HYDROCARBON GENERATION MODEL FOR THE COOPER AND EROMANGA BASINS

2003 ◽  
Vol 43 (1) ◽  
pp. 433 ◽  
Author(s):  
I. Deighton ◽  
J.J. Draper ◽  
A.J. Hill ◽  
C.J. Boreham
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Generation Model ◽  
Hydrocarbon Generation ◽  
Control Points ◽  
Seismic Structure ◽  
Dynamic Topography ◽  
Late Tertiary ◽  
Petroleum Generation ◽  
Eromanga Basin

The aim of the National Geoscience Mapping Accord Cooper-Eromanga Basins Project was to develop a quantitative petroleum generation model for the Cooper and Eromanga Basins by delineating basin fill, thermal history and generation potential of key stratigraphic intervals. Bio- and lithostratigraphic frameworks were developed that were uniform across state boundaries. Similarly cross-border seismic horizon maps were prepared for the C horizon (top Cadna-owie Formation), P horizon (top Patchawarra Formation) and Z horizon (base Eromanga/Cooper Basins). Derivative maps, such as isopach maps, were prepared from the seismic horizon maps.Burial geohistory plots were constructed using standard decompaction techniques, a fluctuating sea level and palaeo-waterdepths. Using terrestrial compaction and a palaeo-elevation for the Winton Formation, tectonic subsidence during the Winton Formation deposition and erosion is the same as the background Eromanga Basin trend—this differs significantly from previous studies which attributed apparently rapid deposition of the Winton Formation to basement subsidence. A dynamic topography model explains many of the features of basin history during the Cretaceous. Palaeo-temperature modelling showed a high heatflow peak from 90–85 Ma. The origin of this peak is unknown. There is also a peak over the last two–five million years.Expulsion maps were prepared for the source rock units studied. In preparing these maps the following assumptions were made:expulsion is proportional to maturity and source rock richness;maturity is proportional to peak temperature; andpeak temperature is proportional to palaeo-heatflow and palaeo-burial.The geohistory modelling involved 111 control points. The major expulsion is in the mid-Cretaceous with minor amounts in the late Tertiary. Maturity maps were prepared by draping seismic structure over maturity values at control points. Draping of maturity maps over expulsion values at the control points was used to produce expulsion maps. Hydrocarbon generation was calculated using a composite kerogen kinetic model. Volumes generated are theoretically large, up to 120 BBL m2 of kitchen area at Tirrawarra North. Maps were prepared for the Patchawarra and Toolachee Formations in the Cooper Basin and the Birkhead and Poolowanna Formations in the Eromanga Basins. In addition, maps were prepared for Tertiary expulsion. The Permian units represent the dominant source as Jurassic source rocks have only generated in the deepest parts of the Eromanga Basin.

HYDROCARBON GENERATION AND EXPULSION FROM EARLY CRETACEOUS SOURCE ROCKS IN THE BROWSE BASIN, NORTH WEST SHELF, AUSTRALIA: A SMALL ANGLE NEUTRON SCATTERING STUDY

2004 ◽  
Vol 44 (1) ◽  
pp. 151 ◽  
Author(s):  
A.P. Radlinski ◽  
J.M. Kennard ◽  
D.S. Edwards ◽  
A.L. Hinde ◽  
R. Davenport
Keyword(s):  
Neutron Scattering ◽  
Pore Size ◽  
Source Rock ◽  
Early Cretaceous ◽  
Small Angle ◽  
Small Angle Neutron Scattering ◽  
Source Rocks ◽  
Geochemical Data ◽  
Hydrocarbon Generation ◽  
North West

Small Angle Neutron Scattering (SANS) analyses were carried out on 165 potential source rocks of Late Jurassic–Early Cretaceous age from nine wells in the Browse Basin (Adele–1, Argus–1, Brecknock South–1, Brewster–1A, Carbine–1, Crux–1, Dinichthys–1, Gorgonichthys–1 and Titanichthys–1). Samples from Brewster–1A and Dinichthys–1 were also analysed using the Ultra Small Angle Neutron Scattering (USANS) technique.The SANS/USANS data detect the presence of generated bitumen and mobile hydrocarbons in pores and are pore-size specific. As the pore-size range in mudstones extends from about 0.001–30 μm, the presence of bitumen in the small pores detected by SANS indicates the depth of onset of hydrocarbon generation, whereas the presence of bitumen and mobile hydrocarbons in the largest pores detected by USANS indicates a significant saturation and the onset of expulsion.Although geochemical data imply the existence of a potential gas and oil source rock in the Lower Cretaceous section (Echuca Shoals and Jamieson Formations), the SANS/USANS data indicate significant generation but little or no expulsion. This source limitation may explain poor exploration success for liquid hydrocarbons in the area. The SANS/USANS data provide evidence of intra- and inter-formational hydrocarbon migration or kerogen kinetics barriers. There is no evidence of an oil charge to the Berriasian Brewster Sandstone from the Echuca Shoals Formation, although some gas charge in Brewster–1A is possible. This novel microstructural technique can be used to independently calibrate and refine source rock generation/expulsion scenarios derived from geochemistry modelling.

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