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The Taranaki Basin in New Zealand is an area of active exploration for oil and condensate. This research focuses on integrating geochemical characteristics and 1-D basin modeling to Late Cretaceous to Miocene source rock systems, along with oil and condensate data from fifty-seven wells in the Taranaki Basin. The geochemical study reveals that the oil and condensate samples were generated from clay-rich source rocks, containing mixed organic matter, with large amounts of terrestrial organic matter input. These source rocks were deposited in fluvial to fluvio-deltaic environments under oxic conditions. The presence of oleanane in both oil and condensate samples suggests that the source rocks had a significant terrestrial component and deposited during the Late Cretaceous to Cenozoic. Using various biomarker proxies, oil-source rock correlation along with 1-D basin modeling revealed that the oil and condensate were mainly derived from the Late Cretaceous Rakopi and Paleocene Farewell formations at different maturity stages. The oils were generated within the peak-mature oil window, while the condensates primarily resulted from the secondary cracking of oil taking place in the source rock within the gas generation window. This finding is consistent with the 1-D basin modeling results. The model shows that the Paleocene Farewell source rock has achieved the primary stage of oil generation (0.55–0.95 Easy %Ro), contributing to most of the discovered oils in the Cenozoic reservoir rocks. Meanwhile, the Late Cretaceous Rakopi source rock reached the gas window with a higher vitrinite reflectance of more than 1.30 Easy %Ro, indicating greater gas generation potential. • Cenozoic oil and condensate reservoirs of the Taranaki Basin have API values between 23.2° and 59. 0°. • The oils and condensates were generated from deltaic clay-source rocks and deposited under oxic conditions. • These oils and condensates are thermally mature, with higher maturity level for the condensates. • The oils and condensates were generated from Farewell and Rakopi source rocks. [ABSTRACT FROM AUTHOR]

The Late Jurassic Meem Shale Member is widely exposed within the Sabatayn Basin, including in the Al-Jawf sub-basin. In this study, a total of 49 shale samples of the Meem Shale Member from two exploratory wells; Dahmar Ali−01 (28 samples in the depth range 1441–2351 m) and Kamaran-01 (21 samples in the depth range 2275–3011 m) in the south-eastern portion of the Al-Jawf sub-basin were studied as possible source rocks. Evaluation of source rock geochemistry including total organic matter (TOC) and Rock-Eval pyrolysis analyses was performed. The results of this study provided information regarding significant exploration of oil and gas resources from the Meem Shale Member in the Al-Jawf sub-basin. Both the incident light microscopic results and the Rock-Eval geochemical study have indicated that the analyzed shale samples contain predominantly Type III kerogen with minor contributions of Type I/II and IV, so as to they can generate both oil and gas. The values of hydrogen index (HI) are decreased with increasing thermal maturity and varied between 34 and 803 mg HC/g TOC. Based on the measured VRo% range of 0.63 and 2.00, the Meem shales are currently within the oil- and gas-generation window, thus, they are considered as shale-oil and -gas resource possible plays. The geochemical results were integrated with geological data of the Al-Jawf sub-basin and incorporated into a basin model to simulate petroleum generation and/or retention in the Meem Shale Member. The constructed basin models illustrated that the Meem Shale Member displayed a peak oil generation window during the Late Jurassic to Early Miocene, where large amounts of oil were generated, with a conversion ratio of 10–75 TR%. Further, the high heating rates from local volcanic rocks from the Early Miocene till date have caused gas generation from both of the original Type III kerogen and from secondary cracking of retained oil in the Meem Shale Member. However, the main contribution of gas generation within the Meem Shale Member came from secondary cracking processes through geologic time. The good thickness (736–910 m) of the organically-rich, high genetic potential and matured Meem Shale Member is expected to provide large amounts of oil and gas within the south-eastern portion of Al-Jawf sub-basin. Therefore, the Al-Jawf sub-basin can be considered as a rich oil and gas exploration province. • Meem shales samples from two wells in the South-eastern Al-Jawf sub-basin were analyzed. • The Meem shales contain Types I/II and III/V kerogen. • The shales are currently at oil and gas-window and large amounts of oil had generated during Late Jurassic to early Miocene. • The mass gas-generation was formed by primary and secondary cracking at high maturity during early Miocene. [ABSTRACT FROM AUTHOR]

Abstract This study is a part of the source rock geochemistry project in the onshore Sabatyen Basin, Yemen. The results of this study were used to improve our understanding of the petroleum resource potential of Al-Jawf sub-basin in the north-western part of the Sabatyen Basin. The shale samples of the Late Jurassic Arwa Member from two wells (Khyawan-01 and Himyar-01) were analyzed to evaluate the characterises of the organic richness, kerogen type, thermal maturity and petroleum generation potential in Al-Jawf sub-basin based on a compilation of geochemical and petrological data. The biomarker and stable isotope results were subsequently used to evaluate the organic source input and sedimentary environmental conditions during deposition of the Late Jurassic Arwa Member shales. The Arwa shales contain low to high organic matter, with variable TOC% values between 0.58 and 6.41, indicating fair to very good source rock generative potential. The Rock-Eval HI data are ranging from 73 to 816 mg HC/g TOC and display mainly Type III and II/III kerogens with a minor contribution of Types I/II kerogen, consistent with both oil and gas source rocks. The biological sources are predominately sapropelic organic matter, with significant contribution of higher plants input in the Arwa member shales as indicated from biomarkers and carbon isotope data and petrology study. The biomarker ratios of relatively low Pr/Ph, Pr/ n -C 17 and Ph/ n -C 18 values and relatively high values of HC 34 /HC 35 indicate suboxic environmental conditions during deposition of the Arwa Member shales. The analyzed Arwa shale samples have temperatures of maximum pyrolysis yield (T max) in the range of 417–457 °C and vitrinite reflectance between 0.30 and 0.56 %Ro, consistent with immature to early-mature source rocks. It is interesting to know that the Arwa shale samples with high contents of TOC% (>1), HI (>300 mg HC/g TOC) and high thickness of more than 1000 m indicate that the Late Jurassic Arwa Member hold significant exploration potential for oil in the deeper locations. Therefore, the hydrocarbon exploration processes should be focused on the known deeper location of the Arwa Member for predicting the mature source rock. Highlights • Arwa shales were classified as fair to good potential source rocks in Al-Jawf sub-basin. • The Arwa shales contain mixed organic matter and deposited under suboxic conditions. • The Arwa shales are considered to be both oil and gas source rocks. • The Arwa shales are still at immature to early-mature stages for oil-generation in the studied wells. [ABSTRACT FROM AUTHOR]

In this study, bituminous shale samples were collected from Late Jurassic sedimentary section in the Marib oilfields to study their petrologic and organic geochemical properties. The results of this study indicate that the Late Jurassic bituminous shales can be considered as an oil-source rocks in the Sabatayn Basin (NW Yemen). The analyzed Late Jurassic shales have high organic matter (TOC up to 10%) content of kerogen Types I/II. These kerogen types in the analyzed samples are consistent with the high dominance of alginite and amorphous organic matter. Open pyrolysis–gas chromatography results are generally consistent with the Rock-Eval results and further indicate that the analyzed shale samples contain Types I/II and II-S kerogen and generally can produce paraffinic oils with low to high wax content. Type II-S kerogen can produce oil with high sulphur content at low maturity level. The maturity data reflect immature and very early maturity stages of petroleum formation of the Late Jurassic bituminous shales. Therefore, the kerogen types in the Late Jurassic bituminous shales has not been altered by thermal maturity for oil generation, thus, artificial heating is required of kerogen cracking generate significant oil. [ABSTRACT FROM AUTHOR]

Integrated petrophysical and petrographic analyses were performed on the Kuhlan clastic rocks to evaluate the petrophysical reservoir properties, identify grain sorting along with the clay type and mineral volumes using well logs coupled with core data. Core samples were collected from two key wells and their results were used to determine the reservoir properties and bulk mineralogical composition and, additionally, to calibrate the well log results from three un-cored to the two cored wells. The Kuhlan clastic reservoir rocks have porosity values between 6% and 12%. These porosity values are mainly intergranular primary and secondary porosity. Permeability is likewise variable with values in the range of 78–304 mD. The Kuhlan reservoir rocks also have high hydrocarbon saturation exceeding 70%, with relatively high movable oil. These reservoir properties are achieved from log-derived and core porosity and permeability results. The lithology and mineral composition of the well logs and petrographic studies in this study indicate that the Kuhlan sandstone can be considered as an alternative reservoir rock in the basin. The Kuhlan Formation is primarily composed of sandstone that contains quartz, feldspar (i.e., orthoclase, plagioclase (albite) minerals and illite, and calcite cements. The quartz mineral is dominant followed by feldspar as the second most abundant mineral in this formation. The Kuhlan Formation sandstones are classified (based on standard rock classification schemes) into arkose, sub-arkose and feldspathic lithofacies. The results of petrographic analysis also indicate a continental block transitional source of the Kuhlan Formation sandstones. Petrographically, the Kuhlan sandstones are poorly sorted and range from fine to coarse-grained and contain high percentages of detrital quartz and feldspar-rich grains with a significant amount of rock fragments. The Kuhlan sandstones also contain a variable range of matrix and cement contents. Based on the results of this study, the reservoir quality of the Kuhlan sandstone ranges between good to poor reservoir quality. The Kuhlan Formation has arkosic and sub-arkosic sandstones that result in a good reservoir quality with a significant increase of the permeability and intergranular porosity. This is attributed to the coarse-grained texture, high percentages of detrital quartz, slightly well sorted texture and the low degree of matrix and cements. In contrast, the Kuhlan Formation feldspathic sandstone has poor reservoir quality due to the poor sorting texture, pore space occluding clayey groundmass, and carbonate cement. [ABSTRACT FROM AUTHOR]

In this study, four exploratory wells from the Mukalla-Sayhut Basin, Gulf of Aden are used for basin modeling study in order to simulate the petroleum generation and expulsion history of the Umm Er Radhuma Formation. The basin models illustrate that the Gulf of Aden is an extensional rift basin and initially developed during Oligocene as indicated by paleo-heat flow values. The heat flow reached peak heat-flow values of approximately 120–160 mW/m 2 at Early to Middle Oligocene time. This high paleo-heat flow had a considerable effect on the Paleocene Umm Er Radhuma source rock and cooking of the organic matter. The basin models also indicate that the Umm Er Radhuma Formation source rock had passed the peak-oil generation window during the late Oligocene (Chattian) age. Onset of oil-generation began during late Rupelian age (∼29 Ma), whereas the main oil was generated during the Chattian age (27-24 Ma). The models also show that the petroleum was expelled from the Umm Er Radhuma source rock since latest Oligocene (late Chattian, < 24Ma) time, with transformation ratio of more than 50%. These basin models suggest that the Umm Er Radhuma Formation is an effective source rock where significant amount of petroleum is expected to be generated and expelled to any nearby potential reservoir rocks within the Mukalla-Sayhut Basin. [ABSTRACT FROM AUTHOR]

A conventional organic geochemical study has been performed on the shale samples collected from the early Cretaceous Saar Formation from the Shabwah oilfields in the Sabatayn Basin, Western Yemen. The results of this study were used to preliminary evaluate the potential source-rock of the shales in the Saar Formation. Organic matter richness, type, and petroleum generation potential of the analysed shales were assessed. Total organic carbon content and Rock- Eval pyrolysis results indicate that the shale intervals within the early Cretaceous Saar Formation have a wide variation in source rock generative potential and quality. The analysed shale samples have TOC content in the range of 0.50 and 5.12 wt% and generally can be considered as fair to good source rocks. The geochemical results of this study also indicate that the analysed shales in the Saar Formation are both oil- and gas-prone source rocks, containing Type II kerogen and mixed Types II-III gradient to Type III kerogen. This is consistent with Hydrogen Index (HI) values between 66 and 552 mg HC/g TOC. The temperature-sensitive parameters such as vitrinite reflectance (%VRo), Rock-Eval pyrolysis T max and PI reveal that the analysed shale samples are generally immature to early-mature for oil-window. Therefore, the organic matter has not been altered by thermal maturity thus petroleum has not yet generated. Therefore, exploration strategies should focus on the known deeper location of the Saar Formation in the Shabwah-sub-basin for predicting the kitchen area. [ABSTRACT FROM AUTHOR]

In this study, oil shale samples were collected from Late Cretaceous Muwaqaar Chalk Marl Formation (MCM) in Jordan to study their petrologic and organic geochemical properties. Pyrolysis and bulk kinetic techniques were performed on the Late Cretaceous oil shales. The results of this study were used to characterize the different organofacie types in the Late Cretaceous oil shales and their effect on the petroleum type generated during thermal maturation and the temperature of petroleum generation. On the basis of the geochemical results, the analysed Late Cretaceous oil shales contain predominantly Type II and rarely Type I kerogens. These kerogens are consistent with the high dominate of sapropel organic matter (i.e., alginite and amorphous organic matter). A good correlation is noted between increasing abundance of organic matter and the kerogen type that was derived from an open pyrolysis–gas chromatography (Py–GC). The Py–GC data indicate the analysed oil shale samples contain heterogeneous organic matter of the kerogen Type II-S. It is interesting to know that this sulphur-rich kerogen (Type II-S) can generate high sulphur oils at low maturity ranges. This is consistent with the predicted temperature petroleum generation from bulk kinetic models. The bulk kinetic models in this study indicate that the main phase of petroleum formation from the thermally immature Late Cretaceous oil shales occur between 122 and 148 °C. These temperature values of the petroleum generation are generally consistent with the kerogen type II-S and further indicate that the analysed oil shale samples can generate sulfur-rich oils at early stage of kerogen cracking. [ABSTRACT FROM AUTHOR]

The Late Miocene Zeit Formation is exposed in the Red Sea Basin of Sudan and represents an important oil-source rock. In this study, five (5) exploratory wells along Red Sea Basin of Sudan are used to model the petroleum generation and expulsion history of the Zeit Formation. Burial/thermal models illustrate that the Red Sea is an extensional rift basin and initially developed during the Late Eocene to Oligocene. Heat flow models show that the present-day heat flow values in the area are between 60 and 109 mW/m 2 . The variation in values of the heat flow can be linked to the raise in the geothermal gradient from margins of the basin towards offshore basin. The offshore basin is an axial area with thick burial depth, which is the principal heat flow source. The paleo-heat flow values of the basin are approximately from 95 to 260 mW/m 2 , increased from Oligocene to Early Pliocene and then decreased exponentially prior to Late Pliocene. This high paleo-heat flow had a considerable effect on the source rock maturation and cooking of the organic matter. The maturity history models indicate that the Zeit Formation source rock passed the late oil-window and converted the oil generated to gas during the Late Miocene. The basin models also indicate that the petroleum was expelled from the Zeit source rock during the Late Miocene (>7 Ma) and it continues to present-day, with transformation ratio of more than 50%. Therefore, the Zeit Formation acts as an effective source rock where significant amounts of petroleum are expected to be generated in the Red Sea Basin. [ABSTRACT FROM AUTHOR]

Calcareous shales and black limestones of the Jurassic Amran Group, located in the Sharab area (SW Yemen), were analysed based on organic and inorganic geochemical methods. The results of this study were used to reconstruct the paleoenvironmental and paleoclimatic conditions during Jurassic time and their relevance to organic matter enrichment during deposition of the Amran calcareous shale and black limestone deposits. The analysed Amran samples have present-day TOC and S total content values in the range of 0.25–0.91 wt % and 0.59–4.96 wt %, respectively. The relationship between S total and TOC contents indicates that the Jurassic Amran deposits were deposited in a marine environment as supported by biomarker environmental indicators. Biomarker distributions also reflect that the analysed Amran deposits received high contributions of marine organic matter (e.g., algal and microbial) with minor amount of land plant source inputs. Low oxygen (reducing) conditions during deposition of the Jurassic Amran deposits are indicated from low Pr/Ph values and relatively high elemental ratios of V/Ni and V/(V + Ni). Enrichment in the pyrite grains and very high DOP T and high Fe/Al ratios further suggest reducing bottom waters. This paleo-redox (i.e., reducing) conditions contributed to preservation of organic matter during deposition of the Jurassic Amran deposits. Semi-arid to warm climatic conditions are also evidenced during deposition of the Amran sediments and consequently increased biological productivity within the photic zone of the water column during deposition. Therefore, the increased bio-productivity in combination with good preservation of organic matter identified as the major mechanisms that gave rise to organic matter enrichment. This contradicts with the low organic matter content of the present-day TOC values of less than 1%. The biomarker maturity data indicate that the analysed Amran samples are of high thermal maturity; therefore, the low present-day TOC is attributed to the thermal effect on the original organic matter. This high thermal maturity level is due to the presence of volcanic rocks, which have invaded the Jurassic rocks during Late Oligocene to Early Miocene. [ABSTRACT FROM AUTHOR]

The Miocene Salif Formation is an oil-source rock within the Tihamah Basin, southern Red Sea of Yemen. The Salif shale beds are characterized by high organic carbon content (TOC) up to 5.59% and high oil saturation index (OSI) (30 < OSI <260 mg HC/g TOC). However, most of the Salif shale samples exhibit OSI values of >100 mg HC/g TOC, indicating a thermally mature and oil-saturated source rock system with high oil-bearing potential. This finding is supported by the vitrinite reflectance values, representing mature oil generation window. Therefore, the shale oil potential of the Salif source rock system is studied for the first time by integrating geochemical data and geological information into a 1-D modelling scheme. The models reconstructed for the thermal and burial history infers that the Salif source rock system is located within the late oil-window from the Late Pliocene to present-day. Kerogen to oil conversion and the timing of petroleum generation and expulsion are also simulated by the 1-D models, showing that 10–50% of the total kerogen is converted into oil during the early Pliocene to the Pleistocene, which is consistent with the peak-late mature oil-window (0.70–1.26 %Ro). The models also exhibited that limited oil was expelled from the Salif source rock system since the Pleistocene-present-day as demonstrated by the TR ratio of up to 55%. The integration of source rock evaluation and modeling approach concludes that the Salif source rock provides a good potential for possible oil production, where suitable reservoir characteristics do occur. • Miocene Salif Formation is a main oil-source rock in the Tihamah Basin. • Salif source rock is currently at a peak to late mature of oil window. • Salif source rock system has a good oil-bearing capacity, with oil saturation index of >100 mg HC/g TOC. • Kerogen was converted into oil with TR ratio between 10% and 55% during the late Miocene until the present-day. [ABSTRACT FROM AUTHOR]

Crude oil samples from Cretaceous and Tertiary reservoir sections in the Zagros Fold Belt oil fields, southern Iraq were investigated using non-biomarker and biomarker parameters. The results of this study have been used to assess source of organic matter, and the genetic link between oils and their potential source rocks in the basin. The oils are characterized by high sulphur and trace metal (Ni, V) contents and relatively low API gravity values (17.4–22.7° API). This indicates that these oils are heavy and generated from a marine source rock containing Type II-S kerogen. This is supported by their biomarker distributions of normal alkanes, regular isoprenoids, terpanes and steranes and the bulk carbon isotope compositions of their saturated and aromatic hydrocarbons. The oils are characterized by low Pr/Ph ratios (<1), high values of the C 35 homohopane index and C 31 -22R/C 30 hopane ratios, relatively high C 27 sterane concentrations, and the predominance of C 29 -norhopane. These biomarkers suggest that the oils were generated predominantly from a marine carbonate source rock, deposited under reducing conditions and containing plankton/algal and microorganisms source input. The presence of gammacerane also suggests water column stratification during source rock deposition. The biomarker characteristics of the oils are consistent with those of the Middle Jurassic Sargelu carbonate as the effective source rock in the basin. Biomarker maturity data indicate that the oils were generated from early maturity source rocks. [ABSTRACT FROM AUTHOR]

Oil shales, located in Lajjun area (Central Jordan), were analyzed based on organic geochemistry, coupled with microscopical study to define the origin, type of organic matter input, and the influencing factors that govern organic matter (OM) enrichment, including the OM preservation conditions. Oil shales are thermally immature petroleum-source rocks for oil that require artificial heating to generate oil of commercial value. The analyzed oil shales have high total sulfur content values in the range of 2.08–4.06 wt%, and the organic carbon contents are also consistently high (>10%). The high total sulfur content and its relation with organic carbon values indicate that the Jordanian oil shales were deposited in a marine environment under reducing conditions. The organic matter input and paleoenvironmental conditions have also been evidenced from their biomarker distributions and microscopic study. The microscopical investigation indicated that the oil shales contain an abundant liptinitic organic matter (i.e., alginite, structureless (amorphous) and planktonic foraminifera). The presence of these liptinitic materials and planktonic foraminifera assemblages in the oil shale samples, further suggests a marine origin. Their biomarkers also provide evidence for a high contribution of marine plankton/algal and microorganisms and persevered under highly hypersalinity reducing conditions. The good preservation under reducing conditions contributes to the high amounts of organic matter enrichment during deposition of these oil shale sediments. Consequently, the Jordanian oil shales have very good oil generative potential, owing to high content of hydrogen rich Type I/II oil-prone kerogen. [ABSTRACT FROM AUTHOR]

Cretaceous sedimentary rocks of the Mukalla, Harshiyat and Qishn formations from three wells in the Jiza sub-basin were studied to describe source rock characteristics, providing information on organic matter type, paleoenvironment of deposition and hydrocarbon generation potential. This study is based on organic geochemical and petrographic analyses performed on cuttings samples. The results were then incorporated into basin models in order to understand the burial and thermal histories and timing of hydrocarbon generation and expulsion. The bulk geochemical results show that the Cretaceous rocks are highly variable with respect to their genetic petroleum generation potential. The total organic carbon (TOC) contents and petroleum potential yield ( S 1 + S 2 ) of the Cretaceous source rocks range from 0.43 to 6.11% and 0.58–31.14 mg HC/g rock, respectively indicating non-source to very good source rock potential. Hydrogen index values for the Early to Late Cretaceous Harshiyat and Qishn formations vary between 77 and 695 mg HC/g TOC, consistent with Type I/II, II-III and III kerogens, indicating oil and gas generation potential. In contrast, the Late Cretaceous Mukalla Formation is dominated by Type III kerogen (HI < 200 mg HC/g TOC), and is thus considered to be gas-prone. The analysed Cretaceous source rock samples have vitrinite reflectance values in the range of 0.37–0.95 Ro% (immature to peak-maturity for oil generation). A variety of biomarkers including n -alkanes, regular isoprenoids, terpanes and steranes suggest that the Cretaceous source rocks were deposited in marine to deltaic environments. The biomarkers also indicate that the Cretaceous source rocks contain a mixture of aquatic organic matter (planktonic/bacterial) and terrigenous organic matter, with increasing terrigenous influence in the Late Cretaceous (Mukalla Formation). The burial and thermal history models indicate that the Mukalla and Harshiyat formations are immature to early mature. The models also indicate that the onset of oil-generation in the Qishn source rock began during the Late Cretaceous at 83 Ma and peak-oil generation was reached during the Late Cretaceous to Miocene (65–21 Ma). The modeled hydrocarbon expulsion evolution suggests that the timing of oil expulsion from the Qishn source rock began during the Miocene (>21 Ma) and persisted to present-day. Therefore, the Qishn Formation can act as an effective oil-source but only limited quantities of oil can be expected to have been generated and expelled in the Jiza sub-basin. [ABSTRACT FROM AUTHOR]

This study is the first attempt which provides information regarding the bulk and quantitative pyrolysis results of the Chia Gara Formation from the Kurdistan region, northern Iraq. Ten representative early-mature to mature samples from the Chia Gara Formation were investigated for TOC contents, Rock Eval pyrolysis, pyrolysis-GC and bulk kinetic parameters. These analyses were used to characterize the petroleum generated during thermal maturation of the Chia Gara source rock and to clarify the quantity of the organic matter and its effect on the timing of petroleum generation. Pyrolysis HI data identified two organic facies with different petroleum generation characteristics; Type II–III kerogen with HI values of >250 mg HC/g TOC, and Type III kerogen with HI values < 100 mg HC/g TOC. These types of kerogen can generate liquid HCs and gas. This is supported by the products of pyrolysis–gas chromatography (Py–GC) analysis of the extracted rock samples. Pyrolysis products show a dominance of a marine organic matter with variable contributions from terrestrial organic matter (Types II–III and III kerogen), and produces mainly paraffinic-naphthenic-aromatic low wax oils with condensate and gas. Bulk kinetic analysis of the Chia Gara source rock indicates a heterogeneous organic matter assemblage, typical of restricted marine environments in general. The activation energy distributions reveal relatively broad and high values, ranging from 40 to 64 kcal/mol with pre-exponential factors varying from 2.2835 E+12/sec to 4.0920 E+13/sec. The predicted petroleum formation temperature of onset (TR 10%) temperatures ranges from 110 to 135 °C, and peak generation temperatures (geological T max ) between 137 °C and 152 °C. The peak generation temperatures reach a transformation ratio in the range of 42–50% TR, thus the Chia Gara source rock could have generated and expelled significant quantities of petroleum hydrocarbons in the Kurdistan of Iraq. [ABSTRACT FROM AUTHOR]

• Overall, Abu Roash (F) carbonate rocks indicate organic matter richness capable of oil generating. • Abu Roash (F) carbonates are currently dominated by high HI values of <300 mg HC/ g TOC and entering the oil-window maturity. • Abu Roash (F) carbonate-rich rocks in the deepest burial depth reached a TR ratio between 10 and 55%, indicating a high probability of oil production. • Abu Roash (F) carbonates have low porosities and poor permeability, requiring a hydraulic fracturing for commercial oil production. This paper systematically analyzes the organic geochemical, petrophysical, and petrographical properties combined with bulk kinetics modeling of the Abu Roash (F) organic-rich carbonate rocks in the Abu El Gharadig Field. The Abu Roash (F) carbonate-rich samples exhibit high organic content with total organic matter (TOC) values up to 3.04 wt%, and mainly Type II kerogen, with a slight gradient to Type II/III and III kerogens, reaching good to very good oil generation potential. This finding of hydrogen-rich kerogen and oil generation potential was also demonstrated by the abundance of fluorescent alginite, amorphous organic matter (AOM), and bituminite organic matter (OM) as established via ultra violet (UV) light microscopy. The maturity indicators demonstrate that most of the examined Abu Roash (F) carbonate-rich samples from the studied wells, with a deep burial depth of more than 3000 m, are thermally mature, thus defining an early mature to moderate-mature stage. The kinetic models suggest that the Abu Roash (F) carbonate-rich rocks in the deepest burial depth, with calculated vitrinite reflectance (%VRo) values in the range of 0.72–0.83 %, have reached kerogen transformation ratio (TR) in the range of 10–55 %, indicating a high probability of oil production. This finding is confirmed by the presence of the oil crossover in these rocks with an oil saturation index (OSI) of more than 100 mg HC/ g rock. The Abu Roash (F) organic-rich carbonates are intractable rocks as implied by low porosities (up to 2.33 %) and poor permeability in the range of 0.0017–0.0039 mD. The pores in these rocks have a wide range in size, including interparticle, fracture, and organic matter (OM) pores, as recognized in the thin section and scanning electron microscopy (SEM). The development of these pore types and their quality is mainly controlled by high mineralogical brittleness (i.e., carbonates) together with the high OM inputs. Based on the above characteristics, the Abu Roash (F) carbonate-rich rocks in the Abu El Gharadig Field are a candidate for unconventional tight oil reservoir potential, which typically require a form of hydraulic fracturing for possible oil production at deeper burial depths. [ABSTRACT FROM AUTHOR]

Organic geochemical and basin modeling methods were used to investigate the potential of thermogenic gas generation from the source rock of the Miocene Salif Formation. The analyzed Salif shales were collected close to the intrusive volcanic rocks intersected by the Kathib-01 well in the offshore Tihamah Basin, Yemeni Red Sea. Generally, the analyzed Salif shale samples have total organic matter (TOC) values up to 3.4 wt %, overall, indicating organic matter richness capable of generating hydrocarbons. The analyzed Salif shale samples have low hydrogen index (HI) values of <200 mg HC/g TOC, indicating mainly Types IV and III kerogen. These results are in contrast with the presence of dominated hydrogen-rich Type-II kerogen in the Salif shales from the close location of the exploration wells e.g., Al-Auch-01, Al-Meethag −01 and Al-Meethag −02. Therefore, the drastic alteration of the original organic matter of Type II and decreasing HI values, as a result of conversion of kerogen to HCs in the studied well, is due to the high thermal maturation as indicated from thermal maturity indicators. The Salif shale samples in the studied well have reached the main stage of the gas generation window, implying that the Salif Formation has substantial thermogenic gas generation. The increase in thermal maturity in the studied well was caused by the presence of the intrusive volcanic rocks that extruded during the Pliocene age as a result of the regional uplift of rift shoulders. Based on the burial/thermal/generation model of the Kathib-01well, the conversion of kerogen to oil and the subsequent cracking of the retained oil into thermogenic gas has been simulated. During the early to late Pliocene age (5–2 Ma), 10 to about 60% of kerogen was converted to oil, matching the peak mature to late mature of oil window (0.75–1.35 %Ro). Moreover, oil was cracked into thermogenic gas during end of the late Pliocene until the present day (2-0 Ma), indicating the beginning of the gas generation window (>1.35% Ro) with a transformation ratio (TR) above 99%. The prediction of a significant charge of thermogenic gas generation from the Salif Formation in the studied Kathib-01 well is due to the presence of the volcanic intrusive rocks extruded during the late Pliocene to present day time. • Salif shales, overall, indicate organic matter richness capable of generating hydrocarbons. • Salif shales are currently dominated by low HI values of <200 mg HC/g TOC and entering the gas-window maturity. • Salif shales contribute to thermogenic gas potential as implied from geochemical and basin modeling results. • Thermogenic gas is generated from Salif shales during the late Pliocene to present day due to the volcanic intrusive rocks. [ABSTRACT FROM AUTHOR]

This study uses organic geochemical and basin modelling results to examine the potential for thermogenic gas generation from oil-to-gas conversion of the organic-rich Lower Cretaceous Al Renk shales in the Melut Basin, South Sudan. The overall geochemical results show that the Al Renk shales are considered good gas-source rocks with total organic carbon (TOC) content >1 wt % and a low hydrogen index (i.e., HI < 150 mg HC/g TOC; mainly Type III kerogen). This finding contrasts with the source of organic matter and biomarkers related to the depositional environment. Based on biomarker indicators, the Al Renk shales contains a mixture of aquatic organic matter with some terrigenous land plants and was deposited under suboxic to relatively oxic settings in a lacustrine environment. The presence of mixed aquatic and terrigenous organic matter in lacustrine shale sediments suggests a mix of Types II and III kerogen as the original organic matter input during deposition. The geochemical and optical maturity indicators represent late-mature oil to gas generation windows, implying that the Al Renk shale has substantial thermogenic gas generation potential. Therefore, high thermal maturation is a crucial factor in drastically altering the original organic matter (OM) and decreasing HI values (conversion of kerogen to hydrocarbons). The kerogen to oil conversion and the subsequent cracking of the retained oil into thermogenic gas have been simulated by the burial/thermal/generation models in the Agordeed-1 well. These models show that nearly 10–50% of kerogen was transformed into oil during the Late Cretaceous (78–68 Ma), correlating with the early to peak mature of oil generation window (0.62–0.85 %Ro). Moreover, oil was expelled from the Al Renk source rock system during the Late Cretaceous to Late Eocene. From the Late Eocene until the present, significant amounts of residual oil were cracked into gas due to the maturation of the gas generation window (>1.30 Easy % Ro), which is ideal for wet gas generation. Consequently, the findings of this study advocate for conventional gas exploration in the Melut Basin's deeper stratigraphic succession, where the Al Renk Shale Formation has reached a high maturity level of the gas generation window. • Al Renk shales are favourable source rocks for petroleum generation potential. • Al Renk shales encompass a mixture of organic matter and were deposited in a lacustrine environment.. • Al Renk shales currently contribute to the generation of thermogenic gas. • Thermogenic gas is formed due to increased thermal maturation during the Late Eocene and continuing till today.. [ABSTRACT FROM AUTHOR]

Tithonian–Berriasian Chia Gara organic-rich rocks, located in Kurdistan (northern Iraq), were analysed based on inorganic and organic geochemistry to define the origin, type of organic matter, and the influencing factors of organic matter (OM) enrichment, including the OM input and preservation, and their relationship to the paleoenvironment conditions. The δ 13 C org values of the Chia Gara rocks range from −29.99‰ to −26.93‰, with average values of approximately −28.8‰, indicating that the organic matter has a predominantly marine origin. Enhanced biological productivity within the photic zone of the water column during deposition of the Chia Gara Fm. is indicated by consistently high organic carbon content in most samples (average 3 wt.%), as well as by bulk geochemical and biomarker characteristics. Major contributions by aquatic algae and microorganisms with a minor terrigenous organic matter contribution are indicated by the n -alkane distribution patterns and the composition of the hopanoids, steroids, and tricyclic terpenoids. Strongly reducing bottom water is indicated by low pristane/phytane ratios, homohopane distribution patterns, and the redox-sensitive trace elements geochemistry. Salinity stratification with alkaline bottom waters is indicated by high Sr/Ba ratios and the presence of gammacerane in the analysed Chia Gara samples. These data indicate that OM enrichment in the Tithonian–Berriasian Chia Gara rocks results from the combination of enhanced biological productivity and salinity stratification with anoxic bottom water conditions, which favoured OM preservation. [ABSTRACT FROM AUTHOR]

The petroleum generating potential of the Late Cretaceous coal within the Mukalla Formation is evaluated. Bulk and quantitative pyrolysis techniques and organic petrology were used to characterize the kerogen composition, generative potential and kinetic models to determine the variability of the organic matter and their effect on the timing of petroleum generation. These measurements identified one major organic facies containing an oil-prone Type II/III kerogen, with HI values >300 mg HC/g TOC that produces mainly paraffinic and paraffinic–naphthenic–aromatic (P–N–A) oils with high wax contents. Bulk kinetic analysis on Late Cretaceous coal samples reveal a relatively broad distribution of activation energies (42–69 kcal/mol). Using a generic heating rate of 3.3 °C/My, the onset temperature for oil generation (TR 10%) is ∼139 °C and the peak generation temperature (geologic T max ) range from 150 to 167 °C. A 1D model predicts that the Mukalla coals in the Jiza-Qamar Basin began oil generation at ∼40 My and reached peak generation ∼20–15 My ago. Therefore, the Mukalla coals could have be generated mature oils in the Jiza-Qamar Basin. [ABSTRACT FROM AUTHOR]

Barremian–Aptian organic-rich shales from Abu Gabra Formation in the Muglad Basin were analysed using geochemical and petrographic analyses. These analyses were used to define the origin, type of organic matters and the influencing factors of diagenesis, including organic matter input and preservation, and their relation to paleoenvironmental and paleoclimate conditions. The bulk geochemical characteristics indicated that the organic-rich shales were deposited in a lacustrine environment with seawater influence under suboxic conditions. Their pyrolysis hydrogen index (HI) data provide evidence for a major contribution by Type I/II kerogen with HI values of >400 mg HC/g TOC and a minor Type II/III contribution with HI values <400 mg HC/g TOC. This is confirmed by kerogen microscopy, whereby the kerogen is characterized by large amounts of structured algae ( Botryococcus ) and structureless (amorphous) with a minor terrigenous organic matter input. An enhanced biological productivity within the photic zone of the water columns is also detected. The increased biological productivity in the organic-rich shales may be related to enhanced semi-arid/humid to humid-warm climate conditions. Therefore, a high bio-productivity in combination with good organic matter preservation favoured by enhanced algae sizes are suggested as the OM enrichment mechanisms within the studied basin. [ABSTRACT FROM AUTHOR]

The Jiza-Qamar Basin in eastern Yemen is still undergoing hydrocarbon exploration and hydrocarbon potential has not been assigned yet. In this study, subsurface samples from two onshore and offshore wells were collected to characterize the source rocks of Dabut Formation and to incorporate into basin modelling in order to know and determine the timing of petroleum generation and expulsion of the Dabut source rocks. Based on organic geochemical analysis, the Dabut sediments have variable TOC content in the range of 0.5–2.5 wt%, indicating fair to good source rock generative potential. The organic matter of Dabut source rock is dominated by Type III kerogen with minor mixed III–II kerogen contributions, and is thus considered to be mainly gas-prone and some oil-prone. This is supported by HI values in the range of 50–212 mg HC/g TOC. Vitrinite reflectance in the range of 0.63–0.88%Ro and pyrolysis T max in the range of 427–454 °C, generally indicate that the Dabut source rocks contain mature organic matter. One-dimensional basin modelling was performed to analyse the hydrocarbon generation and expulsion history of the Dabut source rocks in the Jiza-Qamar Basin based on the reconstruction of the burial and thermal maturity histories in order to improve our understanding of the hydrocarbon generation potential. Calibration of the model with measured vitrinite reflectance (%Ro) and borehole temperature (BHT) data indicates that the paleo-heat-flow was constant during the Late Cretaceous–Paleogene but increased during the Late Paleogene–Neogene and then decreased exponentially from Neogene to present-day. The modelled maturity history predicts that the oil generation (0.5% Ro) in the Dabut source rock began from about 56 Ma to 42 Ma and the peak hydrocarbon generation (0.86% Ro) occurred approximately from 14 Ma to 13 Ma. These models also indicate that the main phase of oil generation was at 56 Ma to 25 Ma, whereas the main phase of gas generation began from about 25 Ma to 14 Ma and still generated in the present-day. [ABSTRACT FROM AUTHOR]

Organic-rich shale layer is present within the syn-rift Madbi Formation of the Masila Basin, representing excellent oil source rock. Twenty-five representative immature to very early-mature source rock samples from the Upper Jurassic Madbi shale sequences were investigated using bulk and quantitative pyrolysis techniques. The analytical program included TOC, pyrolysis (SRA), pyrolysis GC, bulk kinetics, and kerogen microscopy. The results were used to characterize the kerogen composition and type of petroleum generated during thermal maturation from Madbi source rock and to clarify the variability of the organic matter and their effect on the timing of petroleum generation. Pyrolysis data identified two major organic facies with different petroleum generation characteristics; Type II kerogen with HI values of >400 mg HC/g TOC; Type II/III facies with HI values <400 mg HC/g TOC. This is supported by the abundant liptinitic materials (i.e., alginite, structureless (amorphous), and spores). Pyrolysis GC analysis on extracted rock samples show a dominance of a marine aliphatic-rich organic matter with variable contributions from transported terrestrial organic matter and proved to produce mainly paraffinic–naphthenic–aromatic oils with low wax contents. Bulk kinetic analysis on Madbi shale samples indicate that the Type II facies mostly derived from a homogenous organic matter, spans relatively narrow distribution of activation energy (50–54 kcal/mol) and predicted petroleum formation temperature is very different, with onset (TR 10%) temperatures of ∼125 °C (geological T max ∼138 °C). In contrast, the Type II/III facies reveals a relatively broad distribution of activation energies (40 kcal/mol to 62 kcal/mol) that are directly related to the heterogeneity in the organic matter, onset (TR 10%) temperatures of ∼106 °C (geological T max ∼139 °C). The bulk kinetic analysis also suggested that the peak generation temperatures (geological T max ) are variable and ranging from 135 °C to 142 °C, reaching a significant transformation ratio (∼50% TR). Therefore, the Madbi source rock potential could have be generated and expelled mature oils in the Masila Basin. [ABSTRACT FROM AUTHOR]

Widely exposed in the Marib-Shabowah Basin, the early Upper Jurassic Madbi Formation is divided into two units (Lam and Meem, youngest to oldest) believed to be major source rocks. The Madbi source rocks are characterized by relatively high total organic carbon contents (TOC) ranging from 0.5 to 10.0 wt%, meeting the standard as a fair to excellent source rock generative potential. They contain Type II kerogen grading to mixed Type II/III kerogens and Type III kerogen with HI values between 40 and 620 mg HC/g TOC. Vitrinite reflectance values range from 0.41 to 2.61% R o , indicating sufficient thermal maturity for both oil and gas generation. Burial/thermal history models indicate that the Upper Jurassic Madbi source rocks passed the peak of oil generation stage and convert the oil to dry gas in the Late Jurassic to Late Cretaceous time. Oil generation began immediately after deposition in the Late Jurassic time (150–145 Ma) and maximum rates of oil with significant gas have been generated during Late Cretaceous time (110–65 Ma). The peak gas generation occurred during the early Tertiary. The modelled hydrocarbon expulsion evolution suggests that the timing of hydrocarbon expulsion from the Madbi source rocks began in the early Cretaceous (140 Ma) persisted to present-day. The modelling results also indicate that the peak hydrocarbon generation and expulsion from Madbi source rocks in the studied area occurs well after deposition of the seal rock and formation of traps, ensuring entrapment and preservation of migrated hydrocarbons. [ABSTRACT FROM AUTHOR]