Previous studies have postulated the contribution of present-day low-total organic carbon (TOC) marine carbonate source rocks to oil accumulations in the Tabei Uplift, Tarim Basin, China. However, not all present-da...Previous studies have postulated the contribution of present-day low-total organic carbon (TOC) marine carbonate source rocks to oil accumulations in the Tabei Uplift, Tarim Basin, China. However, not all present-day low-TOC carbonates have generated and expelled hydrocarbons; therefore, to distinguish the source rocks that have already expelled sufficient hydrocarbons from those not expelled hydrocarbons, is crucial in source rock evaluation and resource assessment in the Tabei Uplift. Mass balance can be used to identify modern low-TOC carbonates resulting from hydrocarbon expulsion. However, the process is quite complicated, requiring many parameters and coefficients and thus also a massive data source. In this paper, we provide a quick and cost effective method for identifying carbonate source rock with present-day low TOC, using widely available Rock-Eval data. First, we identify present-day low-TOC carbonate source rocks in typical wells according to the mass balance approach. Second, we build an optimal model to evaluate source rocks from the analysis of the rocks' characteristics and their influencing factors, reported as positive or negative values of a dimensionless index of Rock-Eval data (IR). Positive IR corresponds to those samples which have expelled hydrocarbons. The optimal model optimizes complicated calculations and simulation processes; thus it could be widely applicable and competitive in the evaluation of present-day low TOC carbonates. By applying the model to the Rock-Eval dataset of the Tabei Uplift, we identify present-day iow-TOC carbonate source rocks and primarily evaluate the contribution equivalent of 11.87×10^9 t oil.展开更多
How to accurately recover the hydrocarbon loss is a crucial step in reservoir evaluation by Rock-Eval pyrolysis. However, it is very difficult to determine the recovering coefficients because there are numerous factor...How to accurately recover the hydrocarbon loss is a crucial step in reservoir evaluation by Rock-Eval pyrolysis. However, it is very difficult to determine the recovering coefficients because there are numerous factors causing the hydrocarbon loss. Aiming at this problem, a new method named critical point analysis is put forward in this paper. The first step of the method is to find the critical point by drawing the scatterplot of hydrocarbon contents versus the ratio of the light component of with the heavy component of;And the second step is to calculate the recovering coefficient by contrasting the pyrolysis parameters at the critical point of different sample types. This method is not only been explained reasonably theoretically,but also has got a good application effect in Huanghua depression.展开更多
This article prognosticates the hydrocarbon generation potential of core samples from fields A, B, C and D in Niger delta, Nigeria. The objectives of this study are to characterize the quality of these core samples by...This article prognosticates the hydrocarbon generation potential of core samples from fields A, B, C and D in Niger delta, Nigeria. The objectives of this study are to characterize the quality of these core samples by organic geochemical analyses. A total of ten core samples collected from fields A, B, C and D in Niger delta were analyzed using total organic carbon(TOC) content analysis, rock-eval pyrolysis technique. The analytical results of the studied core samples reveal that they have generally high total organic carbon contents(TOC), suggesting that conditions in the Niger delta favour organic matter production and preservation. There is a variation in the kerogen types and this may be attributed to the relative stratigraphic positions of the core samples within the Niger delta. The rock-eval results indicate that the samples from fields C and D contain predominantly Type II kerogen with a capacity to generate oil and gas and hence have good generative potential. The samples from fields A and B contain mainly Type III kerogen and are gas-prone with moderate generative potential.展开更多
The contamination of cuttings and side wall core (SWC) samples in the Bambra 2 well by drilling mud additives and natural hydrocarbons may cause Rock Eval T max (℃) data to be suspect, and affect its uti...The contamination of cuttings and side wall core (SWC) samples in the Bambra 2 well by drilling mud additives and natural hydrocarbons may cause Rock Eval T max (℃) data to be suspect, and affect its utility in the assessment of thermal maturity. The Rock Eval results of 284 cuttings samples, 31 side wall core samples and conventional core samples from the Jurassic Cretaceous sedimentary sequences in the Bambra 2 well are presented in this paper. Significantly lower T max values from cuttings samples compared with T max values from conventional core samples and solvent extracted SWC samples, from the deeper and higher maturity interval, are thought to have been caused by contamination by diesel and other drilling mud additives. The cuttings samples in the Barrow Group of Cretaceous may be contaminated by natural hydrocarbons, resulting their T max values to be 2-10 ℃ lower than a regularly increased T max trend from core samples. This study indicates that more reliable Rock Eval T max data are obtained from the conventional core samples and solvent extracted SWC samples. This study also indicates that the T max values from some SWC samples were also affected by free hydrocarbons, due to the use of diesel as a mud additive as well.展开更多
Hydrocarbon source potential of the Paleogene Pabdeh Formation was studied by means of organic geochemistry and distribution of calcareous nannofossils.Based on the results,an Eoceneaged organic matter(OM)-rich interv...Hydrocarbon source potential of the Paleogene Pabdeh Formation was studied by means of organic geochemistry and distribution of calcareous nannofossils.Based on the results,an Eoceneaged organic matter(OM)-rich interval was identified and traced across different parts of the North Dezful zone and partly Abadan Plain.In order to characterize the OM quality and richness of the studied intervals,Rock-Eval pyrolysis and nannofossils evaluation were performed,and the geochemical data collected along selected wells were correlated to capture the variations of thickness and source potential of the OM-rich interval.Accordingly,remarkable variations were identified within the depth ranges of 2480–2552 m and also 2200–2210 m,which were attributed to the maximum increase in the rate of growth R-selected species.This increase in the productivity rate was found to be well correlated to high Rock-Eval total organic carbon(TOC)and hydrogen index(HI)values.Given that the maturity of Pabdeh Formation in the studied area was found to have reached the oil window,we expect significant hydrocarbon generation(Type II kerogen),making the play economically highly promising.展开更多
The Rock-Eval technique in the last few decades has found extensive application for source rock analysis.The impact of shale particle crush-size and sample weight on key Rock-Eval measurements,viz.the S;curve(heavier ...The Rock-Eval technique in the last few decades has found extensive application for source rock analysis.The impact of shale particle crush-size and sample weight on key Rock-Eval measurements,viz.the S;curve(heavier hydrocarbons released during the non-isothermal pyrolysis-stage)and the S;curve(CO_(2)released from oxidation of organic matter during the oxidation-stage)are investigated in this study.For high and low total organic carbon(TOC)samples of different thermal maturity levels,it is apparent that particle crush-size has a strong influence on the results obtained from RockEval analysis,with the effect being stronger in high-TOC samples.In comparison to the coarser-splits,S;and pyrolyzable carbon(PC)were found to be higher for the finer crush sizes in all the shales studied.The S_(2)CO_(2)oxidation curve shapes of Permian shales show contrasting signatures in comparison to the Paleocene-aged lignitic shale,both from Indian basins.A reduced TOC was observed with rising sample weight for a mature Permian shale from the Jharia basin,while the other shales sampled showed no significant reduction.The results indicate that the S_(2)CO_(2)curve and the S_(2)T_(2),are strongly dependent on the type of organic-matter present and its level of thermal maturity.Sample weight and particle size both influence the S;-curve shapes at different heating rates.With increasing sample weights,an increase in S;-curve magnitude was observed for the shales of diverse maturities.These differences in the S;curve shape lead to substantially different kinetic distributions being fitted to these curves.These findings are considered to have significant implications for the accuracy of reaction kinetics obtained from pyrolysis experiments using different sample characteristics.展开更多
Ditch samples from AP-4, ER-51 and UK-2 offshore Niger Delta were subjected to biostratigraphic and organic geochemical analyses which entail foraminiferal, palynological, Spore Colour Index (SCI), Rock-Eval Pyrolysis...Ditch samples from AP-4, ER-51 and UK-2 offshore Niger Delta were subjected to biostratigraphic and organic geochemical analyses which entail foraminiferal, palynological, Spore Colour Index (SCI), Rock-Eval Pyrolysis and Fourier Transform Infrared Spectroscopy (FTIR) analyses. The results have established N19 and N17;N17, N16 and N15;and N9 and N8 biozones;and P600 and P700 palynological zones. The dominance of palynomaceral (PM) I and II suggests Type III kerogen. PM III and IV (Type II and IV) were recorded. SCI ranges from 3/4 to 5/6 suggesting an early to mature liquid hydrocarbon generation phase. Rock-Eval Pyrolysis shows that the Total Organic Carbon (TOC), Hydrogen Index (HI), Pyrolysis temperature (T<sub>max</sub>), and Vitrinite Reflectance (VR<sub>o</sub>) range from 2.48 wt% - 6.37 wt%, 78 - 258, 411°C - 431°C and 0.26% - 0.69% respectively suggesting high TOC of Type II/III kerogen. FTIR indices show Type I kerogen in all the wells. VRo results range from 0.4 - 0.5 indicating an immature source. High concentrations of aliphatic saturates in identified functional groups indicate a low biodegradation. The abundance and diversity of recovered assemblages and dominance of PM I and II suggest shallow depositional environments with an age range of late Miocene to early Pliocene. Palynomaceral, SCI, and Rock-Eval inference contradict FTIR kerogen type suggesting that IR spectroscopy might not be suitable for kerogen typing and origin. The geochemical and biostratigraphical inferences must be corroborated for a successful evaluation. However, the source rock in the study area has adequate organic matter with the prospect to generate both oil and gas at appropriate maturity.展开更多
The ever-increasing demand for oil and gas has driven its exploration in rather extreme conditions. In Lamu offshore, which is hitherto underexplored, most of the wells already drilled turned out dry save for a few we...The ever-increasing demand for oil and gas has driven its exploration in rather extreme conditions. In Lamu offshore, which is hitherto underexplored, most of the wells already drilled turned out dry save for a few wells with hydrocarbon shows despite the promising reservoir properties and related geological structures. This, therefore, necessitated a source rock evaluation study in the area to ascertain the presence and potential of the source rock by integrating the geochemical data analysis and petroleum system modeling. The shallow Lamu offshore source rock quantity, quality, and maturity have been estimated through the determination of the total organic carbon (TOC) average values, Kerogen typing, and Rock-Eval pyrolysis measurements respectively. Geochemical data for Kubwa-1, Mbawa-1, Pomboo-1, and Simba-1 were evaluated for determining the source rock potential for hydrocarbon generation. Petroleum system modeling was applied in evaluating geological conditions necessary for a successful charge within a software that integrated geochemical and petrophysical characterization of the sedimentary formations in conjunction with boundary conditions that include basal heat flow, sediment-water interface temperature, and Paleo-water depth. The average TOC of 0.89 wt % in the study area suggests a fair organic richness which seems higher in the late cretaceous (0.98 wt %) than in the Paleocene (0.81 wt %). Vitrinite reflectance and T<sub>max</sub> values in the study area indicate the possible presence of both mature and immature source rocks. Type III Kerogen was the most dominant Kerogen type, and gas shows are the most frequent hydrocarbon encountered in the Lamu Basin with a few cases registering type II/III and type II. The charge properties (i.e. Temperature, transformation ratio, and Vitrinite reflectance) over geologic time at each of the wells have been estimated and their spatial variation mapped as seen from the burial history and depth curves overlaid with temperature, transformation ratio, and Vitrinite reflectance respectively. From the upper cretaceous maturity maps, the results seem to favor near coastal regions where average TOC is about 1.4 wt %, Vitrinite reflectance is more than 0.5%, transformation ratio is more than 10%, and temperatures range from 80°C to 160°C. The results postulate the absence of a definitive effective source rock with a likelihood of having cases of potential and possible source rocks. Moreover, greater uncertainty rests on the source rock’s presence and viability tending toward the deep offshore. Geochemical analysis and petroleum system modeling for hydrocarbon source rock evaluation improved the understanding of the occurrence of the possible and potential source rocks and processes necessary for hydrocarbon generation.展开更多
In this study, the secondary well data for Cretaceous to Miocene cutting samples in four deep offshore exploration wells, i.e., Pomboo-1 in the north, Kubwa-1 in the central, Simba-1 and Kiboko-1 in the south of the d...In this study, the secondary well data for Cretaceous to Miocene cutting samples in four deep offshore exploration wells, i.e., Pomboo-1 in the north, Kubwa-1 in the central, Simba-1 and Kiboko-1 in the south of the deep offshore Lamu Basin were assessed for identifying source rock presence and examining thermal maturity of the source rocks. The 2D basin modelling was used to analyse the bulk gas transformation in the basin. Total organic carbon (TOC) content values for the wells range from 0.09 wt % to 2.23 wt % with an average of 0.78 wt %. The average organic richness is higher in the Upper Cretaceous (0.83 wt %) than in the Palaeogene (0.65 wt %), Lower Cretaceous (0.28 wt %) and Upper Jurassic (0.30 wt %). The S_(1) averages for the Upper Cretaceous are 3.76 mg HC/g rock in Pomboo-1 and 0.31mg HC/g rock in Kubwa-1. The S_(2) averages for the Upper Cretaceous are 5.00 mg HC/g rock in Pomboo-1 and 0.72 mg HC/g rock in Kubwa-1. Hydrogen index (HI) values vary between 4 and 512 mg HC/g TOC with an average of 157.09 mg HC/g TOC. Organic matters were identified as mixed types of Ⅱ-Ⅲ (oil and gas prone) and Ⅲ-Ⅳ (gas prone) kerogen in the potential source rocks. The HI and S_(2) yield values are exceptionally high for the observed TOC values in Pomboo-1. The vitrinite reflectance and Tmax values of deep offshore Lamu Basin are in the ranges of 0.38%–0.72% and 360–441 ℃, respectively. It suggests the existence of both immature and mature source rocks. Vitrinite reflectance maturity favours near coastal region in the Upper Cretaceous. These results explain why Pomboo-1, Kubwa-1, Simba-1 and Kiboko-1 wells were dry. The temperatures are still cool for hydrocarbon generation in deep offshore. The critical risk for deep offshore Lamu Basin is charge, primarily source presence, and a lack of definitive evidence of a deep-water marine source rock being present. The four wells penetrate good quality reservoir and seal rocks, but source rock presence and maturity remain the critical play risk in the deep offshore Lamu Basin.展开更多
基金supported by the China Postdoctoral Science Foundation (grant No. 2017M611108)the National Science and Technology Major Project of China (grant No. 2016ZX05006006-001)the National Basic Research Program of China (grant Nos. 2011CB2011-02 and 2014CB239100)
文摘Previous studies have postulated the contribution of present-day low-total organic carbon (TOC) marine carbonate source rocks to oil accumulations in the Tabei Uplift, Tarim Basin, China. However, not all present-day low-TOC carbonates have generated and expelled hydrocarbons; therefore, to distinguish the source rocks that have already expelled sufficient hydrocarbons from those not expelled hydrocarbons, is crucial in source rock evaluation and resource assessment in the Tabei Uplift. Mass balance can be used to identify modern low-TOC carbonates resulting from hydrocarbon expulsion. However, the process is quite complicated, requiring many parameters and coefficients and thus also a massive data source. In this paper, we provide a quick and cost effective method for identifying carbonate source rock with present-day low TOC, using widely available Rock-Eval data. First, we identify present-day low-TOC carbonate source rocks in typical wells according to the mass balance approach. Second, we build an optimal model to evaluate source rocks from the analysis of the rocks' characteristics and their influencing factors, reported as positive or negative values of a dimensionless index of Rock-Eval data (IR). Positive IR corresponds to those samples which have expelled hydrocarbons. The optimal model optimizes complicated calculations and simulation processes; thus it could be widely applicable and competitive in the evaluation of present-day low TOC carbonates. By applying the model to the Rock-Eval dataset of the Tabei Uplift, we identify present-day iow-TOC carbonate source rocks and primarily evaluate the contribution equivalent of 11.87×10^9 t oil.
文摘How to accurately recover the hydrocarbon loss is a crucial step in reservoir evaluation by Rock-Eval pyrolysis. However, it is very difficult to determine the recovering coefficients because there are numerous factors causing the hydrocarbon loss. Aiming at this problem, a new method named critical point analysis is put forward in this paper. The first step of the method is to find the critical point by drawing the scatterplot of hydrocarbon contents versus the ratio of the light component of with the heavy component of;And the second step is to calculate the recovering coefficient by contrasting the pyrolysis parameters at the critical point of different sample types. This method is not only been explained reasonably theoretically,but also has got a good application effect in Huanghua depression.
文摘This article prognosticates the hydrocarbon generation potential of core samples from fields A, B, C and D in Niger delta, Nigeria. The objectives of this study are to characterize the quality of these core samples by organic geochemical analyses. A total of ten core samples collected from fields A, B, C and D in Niger delta were analyzed using total organic carbon(TOC) content analysis, rock-eval pyrolysis technique. The analytical results of the studied core samples reveal that they have generally high total organic carbon contents(TOC), suggesting that conditions in the Niger delta favour organic matter production and preservation. There is a variation in the kerogen types and this may be attributed to the relative stratigraphic positions of the core samples within the Niger delta. The rock-eval results indicate that the samples from fields C and D contain predominantly Type II kerogen with a capacity to generate oil and gas and hence have good generative potential. The samples from fields A and B contain mainly Type III kerogen and are gas-prone with moderate generative potential.
文摘The contamination of cuttings and side wall core (SWC) samples in the Bambra 2 well by drilling mud additives and natural hydrocarbons may cause Rock Eval T max (℃) data to be suspect, and affect its utility in the assessment of thermal maturity. The Rock Eval results of 284 cuttings samples, 31 side wall core samples and conventional core samples from the Jurassic Cretaceous sedimentary sequences in the Bambra 2 well are presented in this paper. Significantly lower T max values from cuttings samples compared with T max values from conventional core samples and solvent extracted SWC samples, from the deeper and higher maturity interval, are thought to have been caused by contamination by diesel and other drilling mud additives. The cuttings samples in the Barrow Group of Cretaceous may be contaminated by natural hydrocarbons, resulting their T max values to be 2-10 ℃ lower than a regularly increased T max trend from core samples. This study indicates that more reliable Rock Eval T max data are obtained from the conventional core samples and solvent extracted SWC samples. This study also indicates that the T max values from some SWC samples were also affected by free hydrocarbons, due to the use of diesel as a mud additive as well.
基金supported by the Exploration Directorate of National Iranian Oil Company(NIOC)。
文摘Hydrocarbon source potential of the Paleogene Pabdeh Formation was studied by means of organic geochemistry and distribution of calcareous nannofossils.Based on the results,an Eoceneaged organic matter(OM)-rich interval was identified and traced across different parts of the North Dezful zone and partly Abadan Plain.In order to characterize the OM quality and richness of the studied intervals,Rock-Eval pyrolysis and nannofossils evaluation were performed,and the geochemical data collected along selected wells were correlated to capture the variations of thickness and source potential of the OM-rich interval.Accordingly,remarkable variations were identified within the depth ranges of 2480–2552 m and also 2200–2210 m,which were attributed to the maximum increase in the rate of growth R-selected species.This increase in the productivity rate was found to be well correlated to high Rock-Eval total organic carbon(TOC)and hydrogen index(HI)values.Given that the maturity of Pabdeh Formation in the studied area was found to have reached the oil window,we expect significant hydrocarbon generation(Type II kerogen),making the play economically highly promising.
基金awarding BH the CSIR-CIMFR in-house research grant(No.MLP-93/2019-20),the funds of which were utilized to purchase the Rock-Eval 6 device at CSIR-CIMFR and conduct the research。
文摘The Rock-Eval technique in the last few decades has found extensive application for source rock analysis.The impact of shale particle crush-size and sample weight on key Rock-Eval measurements,viz.the S;curve(heavier hydrocarbons released during the non-isothermal pyrolysis-stage)and the S;curve(CO_(2)released from oxidation of organic matter during the oxidation-stage)are investigated in this study.For high and low total organic carbon(TOC)samples of different thermal maturity levels,it is apparent that particle crush-size has a strong influence on the results obtained from RockEval analysis,with the effect being stronger in high-TOC samples.In comparison to the coarser-splits,S;and pyrolyzable carbon(PC)were found to be higher for the finer crush sizes in all the shales studied.The S_(2)CO_(2)oxidation curve shapes of Permian shales show contrasting signatures in comparison to the Paleocene-aged lignitic shale,both from Indian basins.A reduced TOC was observed with rising sample weight for a mature Permian shale from the Jharia basin,while the other shales sampled showed no significant reduction.The results indicate that the S_(2)CO_(2)curve and the S_(2)T_(2),are strongly dependent on the type of organic-matter present and its level of thermal maturity.Sample weight and particle size both influence the S;-curve shapes at different heating rates.With increasing sample weights,an increase in S;-curve magnitude was observed for the shales of diverse maturities.These differences in the S;curve shape lead to substantially different kinetic distributions being fitted to these curves.These findings are considered to have significant implications for the accuracy of reaction kinetics obtained from pyrolysis experiments using different sample characteristics.
文摘Ditch samples from AP-4, ER-51 and UK-2 offshore Niger Delta were subjected to biostratigraphic and organic geochemical analyses which entail foraminiferal, palynological, Spore Colour Index (SCI), Rock-Eval Pyrolysis and Fourier Transform Infrared Spectroscopy (FTIR) analyses. The results have established N19 and N17;N17, N16 and N15;and N9 and N8 biozones;and P600 and P700 palynological zones. The dominance of palynomaceral (PM) I and II suggests Type III kerogen. PM III and IV (Type II and IV) were recorded. SCI ranges from 3/4 to 5/6 suggesting an early to mature liquid hydrocarbon generation phase. Rock-Eval Pyrolysis shows that the Total Organic Carbon (TOC), Hydrogen Index (HI), Pyrolysis temperature (T<sub>max</sub>), and Vitrinite Reflectance (VR<sub>o</sub>) range from 2.48 wt% - 6.37 wt%, 78 - 258, 411°C - 431°C and 0.26% - 0.69% respectively suggesting high TOC of Type II/III kerogen. FTIR indices show Type I kerogen in all the wells. VRo results range from 0.4 - 0.5 indicating an immature source. High concentrations of aliphatic saturates in identified functional groups indicate a low biodegradation. The abundance and diversity of recovered assemblages and dominance of PM I and II suggest shallow depositional environments with an age range of late Miocene to early Pliocene. Palynomaceral, SCI, and Rock-Eval inference contradict FTIR kerogen type suggesting that IR spectroscopy might not be suitable for kerogen typing and origin. The geochemical and biostratigraphical inferences must be corroborated for a successful evaluation. However, the source rock in the study area has adequate organic matter with the prospect to generate both oil and gas at appropriate maturity.
文摘The ever-increasing demand for oil and gas has driven its exploration in rather extreme conditions. In Lamu offshore, which is hitherto underexplored, most of the wells already drilled turned out dry save for a few wells with hydrocarbon shows despite the promising reservoir properties and related geological structures. This, therefore, necessitated a source rock evaluation study in the area to ascertain the presence and potential of the source rock by integrating the geochemical data analysis and petroleum system modeling. The shallow Lamu offshore source rock quantity, quality, and maturity have been estimated through the determination of the total organic carbon (TOC) average values, Kerogen typing, and Rock-Eval pyrolysis measurements respectively. Geochemical data for Kubwa-1, Mbawa-1, Pomboo-1, and Simba-1 were evaluated for determining the source rock potential for hydrocarbon generation. Petroleum system modeling was applied in evaluating geological conditions necessary for a successful charge within a software that integrated geochemical and petrophysical characterization of the sedimentary formations in conjunction with boundary conditions that include basal heat flow, sediment-water interface temperature, and Paleo-water depth. The average TOC of 0.89 wt % in the study area suggests a fair organic richness which seems higher in the late cretaceous (0.98 wt %) than in the Paleocene (0.81 wt %). Vitrinite reflectance and T<sub>max</sub> values in the study area indicate the possible presence of both mature and immature source rocks. Type III Kerogen was the most dominant Kerogen type, and gas shows are the most frequent hydrocarbon encountered in the Lamu Basin with a few cases registering type II/III and type II. The charge properties (i.e. Temperature, transformation ratio, and Vitrinite reflectance) over geologic time at each of the wells have been estimated and their spatial variation mapped as seen from the burial history and depth curves overlaid with temperature, transformation ratio, and Vitrinite reflectance respectively. From the upper cretaceous maturity maps, the results seem to favor near coastal regions where average TOC is about 1.4 wt %, Vitrinite reflectance is more than 0.5%, transformation ratio is more than 10%, and temperatures range from 80°C to 160°C. The results postulate the absence of a definitive effective source rock with a likelihood of having cases of potential and possible source rocks. Moreover, greater uncertainty rests on the source rock’s presence and viability tending toward the deep offshore. Geochemical analysis and petroleum system modeling for hydrocarbon source rock evaluation improved the understanding of the occurrence of the possible and potential source rocks and processes necessary for hydrocarbon generation.
文摘In this study, the secondary well data for Cretaceous to Miocene cutting samples in four deep offshore exploration wells, i.e., Pomboo-1 in the north, Kubwa-1 in the central, Simba-1 and Kiboko-1 in the south of the deep offshore Lamu Basin were assessed for identifying source rock presence and examining thermal maturity of the source rocks. The 2D basin modelling was used to analyse the bulk gas transformation in the basin. Total organic carbon (TOC) content values for the wells range from 0.09 wt % to 2.23 wt % with an average of 0.78 wt %. The average organic richness is higher in the Upper Cretaceous (0.83 wt %) than in the Palaeogene (0.65 wt %), Lower Cretaceous (0.28 wt %) and Upper Jurassic (0.30 wt %). The S_(1) averages for the Upper Cretaceous are 3.76 mg HC/g rock in Pomboo-1 and 0.31mg HC/g rock in Kubwa-1. The S_(2) averages for the Upper Cretaceous are 5.00 mg HC/g rock in Pomboo-1 and 0.72 mg HC/g rock in Kubwa-1. Hydrogen index (HI) values vary between 4 and 512 mg HC/g TOC with an average of 157.09 mg HC/g TOC. Organic matters were identified as mixed types of Ⅱ-Ⅲ (oil and gas prone) and Ⅲ-Ⅳ (gas prone) kerogen in the potential source rocks. The HI and S_(2) yield values are exceptionally high for the observed TOC values in Pomboo-1. The vitrinite reflectance and Tmax values of deep offshore Lamu Basin are in the ranges of 0.38%–0.72% and 360–441 ℃, respectively. It suggests the existence of both immature and mature source rocks. Vitrinite reflectance maturity favours near coastal region in the Upper Cretaceous. These results explain why Pomboo-1, Kubwa-1, Simba-1 and Kiboko-1 wells were dry. The temperatures are still cool for hydrocarbon generation in deep offshore. The critical risk for deep offshore Lamu Basin is charge, primarily source presence, and a lack of definitive evidence of a deep-water marine source rock being present. The four wells penetrate good quality reservoir and seal rocks, but source rock presence and maturity remain the critical play risk in the deep offshore Lamu Basin.