Well Log Petrophysics of the Cretaceous Pay Zones in Zubair Field, Basrah, South Iraq

Discovered in 1949 with a rate of (195,000) bbl/day from pay zones in Mishrif and Zubair Formation, the expected production of Zubair field is anticipated to be 1125 million bbl/day. Despite this production history, there is a major deficiency in detailed petrophysical analysis of the producing zones. In the present study well log data of 7 wells, selected from numerous wells, are investigated in details to examine the reservoir properties and characterize the reservoir architecture. The petrophysical analysis of Mishrif Formation indicated two or three pay zones. Lithologically, all zones of Mishrif Formation are dominantly clean limestone to dolomitic limestone with zone 2 and 3 reporting higher dolomitic content (20% to 40%) compared to zone 1 (6% to 13%). Mishrif pay zones indicated a relatively good porosity (18% - 24%) with zone 2 predominant in secondary porosity associating dolomitization processes. In Zubair Formation one pay zone is identified but locally could separate into two zones. The clay content is generally low with average content between 2% and 3% while the average porosity showed slightly better values in zone 1 (~0.20) compared to average porosity of zone 2 (0.17) that is rich in silt content associating deposition at a relatively deeper parts of the shelf. The average water saturation shows distinct lower values that vary between 15% and 18.7%. The petrophysical results are statistically analyzed and property histograms and crossplots are constructed to investigate mutual relationships. Such analysis is essential for understanding the reservoir architecture and calculations of reservoir capacity for future development.

Reservoir quality evaluation of the Narimba Formation in Bass Basin,Australia:Implications from petrophysical analysis,sedimentological features,capillary pressure and wetting fluid saturation

The evaluation of reservoir quality was accomplished on the Late Paleocene to Early Eocene Narimba Formation in Bass Basin,Australia.This study involved combination methods such as petrophysical analysis,petrography and sedimentological studies,reservoir quality and fluid flow units from derivative parameters,and capillary pressure and wetting fluid saturation relationship.Textural and diagenetic features are affecting the reservoir quality.Cementation,compaction,and presence of clay minerals such as kaolinite are found to reduce the quality while dissolution and secondary porosity are noticed to improve it.It is believed that the Narimba Formation is a potential reservoir with a wide range of porosity and permeability.Porosity ranges from 3.1%to 25.4%with a mean of 15.84%,while permeability ranges between 0.01 mD and 510 mD,with a mean of 31.05 mD.Based on the heterogenous lithology,the formation has been categorized into five groups based on permeability variations.Group I showed an excellent to good quality reservoir with coarse grains.The impacts of both textural and diagenetic features improve the reservoir and producing higher reservoir quality index(RQI)and flow zone indicators(FZI)as well as mostly mega pores.The non-wetting fluid migration has the higher possibility to flow in the formation while displacement pressure recorded as zero.Group II showed a fair quality reservoir with lower petrophysical properties in macro pores.The irreducible water saturation is increasing while the textural and digenetic properties are still enhancing the reservoir quality.Group III reflects lower quality reservoir with mostly macro pores and higher displacement pressure.It may indicate smaller grain size and increasing amount of cement and clay minerals.Group IV,and V are interpreted as a poor-quality reservoir that has lower RQI and FZI.The textural and digenetic features are negatively affecting the reservoir and are leading to smaller pore size and pore throat radii(r35)values to be within the range of macro,meso-,micro-,and nano pores.The capillary displacement pressure curves of the three groups show increases reaching the maximum value of 400 psia in group V.Agreement with the classification of permeability,r35 values,and pore type can be used in identifying the quality of reservoir.

Characterization of Organic-Rich Shales for Petroleum Exploration & Exploitation: A Review-Part 3: Applied Geomechanics, Petrophysics and Reservoir Modeling

Modeling geomechanical properties of shales to make sense of their complex properties is at the forefront of petroleum exploration and exploitation application and has received much re- search attention in recent years. A shale＇s key geomechanical properties help to identify its ＂fracibility＂ its fluid flow patterns and rates, and its in-place petroleum resources and potential commercial re- serves. The models and the information they provide, in turn, enable engineers to design drilling pat- terns, fracture-stimulation programs and materials selection that will avoid formation damage and op- timize recovery of petroleum. A wide-range of tools, technologies, experiments and mathematical techniques are deployed to achieve this. Characterizing the interconnected fracture, permeability and porosity network is an essential step in understanding a shales highly-anisotropic features on multiple scales （nano to macro）. Weli-log data, and its petrophysical interpretation to calibrate many geome- chanical metrics to those measured in rock samples by laboratory techniques plays a key role in pro- viding affordable tools that can be deployed cost-effectively in multiple well bores. Likewise, micro- seismic data helps to match fracture density and propagation observed on a reservoir scale with pre- dictions from simulations and laboratory tests conducted on idealised/simplified discrete fracture net- work models. Shales complex wettability, adsorption and water imbibition characteristics have a sig- nificant influence on potential formation damage during stimulation and the short-term and long-term flow of petroleum achievable. Many gas flow mechanisms and models are proposed taking into ac- count the multiple flow mechanisms involved （e.g., desorption, diffusion, slippage and viscous flow op- erating at multiple porosity levels from nano- to macro-scales）. Fitting historical production data and well decline curves to model predictions helps to verify whether model＇s geomechanical assumptions are realistic or not. This review discusses the techniques applied and the models developed that are relevant to applied geomechanics, highlighting examples of their application and the numerous out- standin~ questions associated with them.

Petrophysics characteristics of coalbed methane reservoir: a comprehensive review

Petrophysics of coals directly affects the development of coalbed methane(CBM).Based on the analysis of the representative academic works at home and abroad,the recent progress on petrophysics characteristics was reviewed from the aspects of the scale-span porefracture structure,permeability,reservoir heterogeneity,and its controlling factors.The results showed that the characterization of pore-fracture has gone through three stages:qualitative and semiquantitative evaluation of porefracture by various techniques,quantitatively refined characterization of pore-fracture by integrating multiple methods including nuclear magnetic resonance analysis,liquid nitrogen,and mercury intrusion,and advanced quantitative characterization methods of pore-fracture by high-precision experimental instruments(focused-ion beam-scanning electron microscopy,small-angle neutron scattering and computed tomography scanner)and testing methods(m-CT scanning and X-ray diffraction).The effects of acoustic field can promote the diffusion of CBM and generally increase the permeability of coal reservoirs by more than 10%.For the controlling factors of reservoir petrophysics,tectonic stress is the most crucial factor in determining permeability,while the heterogeneity of CBM reservoirs increases with the enhancement of the tectonic deformation and stress field.The study on lithology heterogeneity of deep and high-dip coal measures,the spatial storage-seepage characteristics with deep CBM reservoirs,and the optimizing production between coal measures should be the leading research directions.

A review of in situ carbon mineralization in basalt

Global warming has greatly threatened the human living environment and carbon capture and storage(CCS)technology is recognized as a promising way to reduce carbon emissions.Mineral storage is considered a reliable option for long-term carbon storage.Basalt rich in alkaline earth elements facilitates rapid and permanent CO_(2) fixation as carbonates.However,the complex CO_(2)-fluid-basalt interaction poses challenges for assessing carbon storage potential.Under different reaction conditions,the carbonation products and carbonation rates vary.Carbon mineralization reactions also induce petrophysical and mechanical responses,which have potential risks for the long-term injectivity and the carbon storage safety in basalt reservoirs.In this paper,recent advances in carbon mineralization storage in basalt based on laboratory research are comprehensively reviewed.The assessment methods for carbon storage potential are introduced and the carbon trapping mechanisms are investigated with the identification of the controlling factors.Changes in pore structure,permeability and mechanical properties in both static reactions and reactive percolation experiments are also discussed.This study could provide insight into challenges as well as perspectives for future research.

Improved reservoir characterization by means of supervised machine learning and model-based seismic impedance inversion in the Penobscot field,Scotian Basin

The present research work attempted to delineate and characterize the reservoir facies from the Dawson Canyon Formation in the Penobscot field,Scotian Basin.An integrated study of instantaneous frequency,P-impedance,volume of clay and neutron-porosity attributes,and structural framework was done to unravel the Late Cretaceous depositional system and reservoir facies distribution patterns within the study area.Fault strikes were found in the EW and NEE-SWW directions indicating the dominant course of tectonic activities during the Late Cretaceous period in the region.P-impedance was estimated using model-based seismic inversion.Petrophysical properties such as the neutron porosity(NPHI)and volume of clay(VCL)were estimated using the multilayer perceptron neural network with high accuracy.Comparatively,a combination of low instantaneous frequency(15-30 Hz),moderate to high impedance(7000-9500 gm/cc*m/s),low neutron porosity(27%-40%)and low volume of clay(40%-60%),suggests fair-to-good sandstone development in the Dawson Canyon Formation.After calibration with the welllog data,it is found that further lowering in these attribute responses signifies the clean sandstone facies possibly containing hydrocarbons.The present study suggests that the shale lithofacies dominates the Late Cretaceous deposition(Dawson Canyon Formation)in the Penobscot field,Scotian Basin.Major faults and overlying shale facies provide structural and stratigraphic seals and act as a suitable hydrocarbon entrapment mechanism in the Dawson Canyon Formation's reservoirs.The present research advocates the integrated analysis of multi-attributes estimated using different methods to minimize the risk involved in hydrocarbon exploration.

Evaluation of Hydrocarbon Potential Using AVO Analysis in the FORMAT Field, Niger Delta Basin, Nigeria

The study involved the evaluation of the hydrocarbon potential of FORMAT Field, coastal swamp depobelt Niger delta, Nigeria to obtain a more efficient reservoir characterization and fluid properties identification. Despite advances in seismic data interpretation using traditional 3D seismic data interpretation, obtaining adequate reservoir characteristics at the finest level had proved very challenging with often disappointing results. A method that integrates the amplitude variation with offfset (AVO) analysis is hereby proposed to better illuminate the reservoir. The Hampson Russell 10.3 was used to integrate and study the available seismic and well data. The reservoir of interest was delineated using the available suite of petrophysical data. This was marked by low gamma ray, high resistivity, and low acoustic impedance between a true subsea vertical depth (TVDss) range of 10,350 - 10,450 ft. The AVO fluid substitution yielded a decrease in the density values of pure gas (2.3 - 1.6 g/cc), pure oil (2.3 - 1.8 g/cc) while the Poisson pure brine increased (2.3 to 2.8 g/cc). Result from FORMAT 26 plots yielded a negative intercept and negative gradient at the top and a positive intercept and positive gradient at the Base which conforms to Class III AVO anomaly. FORMAT 30 plots yielded a negative intercept and positive gradient at the top and a positive intercept and negative gradient at the Base which conforms to class IV AVO anomaly. AVO attribute volume slices decreased in the Poisson ratio (0.96 to - 1.0) indicating that the reservoir contains hydrocarbon. The s-wave reflectivity and the product of the intercept and gradient further clarified that there was a Class 3 gas sand in the reservoir and the possibility of a Class 4 gas sand anomaly in that same reservoir.

Petrophysical Evaluation of Cape Three Points Reservoirs

The findings of a study to ascertain and assess the petrophysical characteristics of Cape Three Points reservoirs in the Western basin with a view to describe the reservoir quantitatively using Well Logs, Petrel and Techlog. The investigated characteristics, which were all deduced from geophysical wire-line logs, include lithology, porosity, permeability, fluid saturation, and net to gross thickness. To characterise the reservoir on the field, a suite of wire-line logs including gamma ray, resistivity, spontaneous potential, and density logs for three wells (WELL_1X, WELL_2X, and WELL_3X) from the Tano Cape Three Point basin were studied. The analyses that were done included lithology delineation, reservoir identification, and petrophysical parameter determination for the identified reservoirs. The tops and bases of the three wells analysed were marked at a depth of 1203.06 - 2015.64 m, 3863.03 - 4253.85 m and 2497.38 - 2560.32 m respectively. There were no hydrocarbons in the reservoirs from the studies. The petrophysical parameters computed for each reservoir provided porosities of 13%, 3% and 11% respectively. The water saturation also determined for these three wells (WELL_1X, WELL_2X and WELL_3X) were 94%, 95% and 89% respectively. These results together with the behaviour of the density and neutron logs suggested that these wells are wildcat wells.

Fluvial reservoir characterization through channel belt dimension and petrophysical analysis

The dimensions and connectivity of fluvial reservoirs vary greatly, making it challenging to characterize them using conventional approaches. In this study integrated channel belt dimension analysis from seismic geomorphology and empirical equations, well log facies, and petrophysical analysis were performed to characterize the fluvial reservoirs. The study interval consists of fluvial deposits and is divided into three reservoir zones, which are defined by four key regional markers (B, D, K, O). In these intervals, six (6) fluvial facies have been identified. Based on the log facies proportions and their stacking relationships, it is interpreted that the reservoirs in zone 1 (B to D) were deposited in a proximal reach of a meandering system, zone 2 (D to K) in a marginal marine setting, and zone 3 (K) in a distal reach of a meandering system. The dimensions of fluvial channels and channel belts were determined using empirical equations. The results were compared with the observed dimensions of fluvial channels and channel belts from the seismic horizon and stratal slices of the same intervals. Zones 1 and 3 are characterized by broad meander belts (1000–4000 m) compared to zone 2 (600–1300 m). Petrophysical analysis showed zones 1 and 3 have the better petrophysical properties compared to zone 2. Though zone 3 has the most well-developed sand bodies, the best reservoir interval is zone 1 because of its higher porosity. Although channel belt dimensions have a significant influence on reservoir connectivity, they do not seem to have control on reservoir properties. The channel belt dimensions obtained from the empirical equations and interpreted from the seismic geomorphology analysis were found to be strikingly similar. Since three-dimensional seismic data is not available everywhere and seismic imaging quality decreases with depth, empirical equations can be used to analyze fluvial reservoir parameters and their connectivity at greater depths.

2D seismic interpretation of Sawan gas field integrated with petrophysical analysis:A case study from Lower Indus Basin,Pakistan

The Lower Indus Basin is the leading hydrocarbon-bearing sedimentary basin in Pakistan.This study has been conducted on the Sawan gas field located in the Lower Indus Basin,adjacent to a few other wellknown gas fields of Pakistan like Kadanwari,Qadirpur,and Miano gas fields.This research aims to present the spatial distribution and reservoir potential of the productive zones of the Lower Goru Formation.The present study utilized various two-dimensional(2D)seismic lines and well-log data(Sawan-01 and Sawan-02)to investigate the structural and stratigraphic features of the area.The stratigraphic layers are mildly deepening in the southeast direction.The 2D seismic interpretation of the research area identifies the existence of extensional remanents,i.e.,normal faults.These extensional structures are associated with horst and graben geometry that acts as a trapping mechanism for hydrocarbons.Wireline logs are used to identify the reservoir's diverse lithology and petrophysical properties.Petrophysical results indicate fair to good effective porosities,low shale volume,and high hydrocarbon saturation(>55%),signifying good reservoir potential in C interval of the Lower Goru Formation.

Modeling and petrophysical properties of digital rock models with various pore structure types: An improved workflow

Pore structure is a crucial factor affecting the physical properties of porous materials,and understanding the mechanisms and laws of these effects is of great significance in the fields of geosciences and petroleum engineering.However,it remains a challenge to accurately understand and quantify the relationship between pore structures and effective properties.This paper improves a workflow to focus on investigating the effect of pore structure on physical properties.First,a hybrid modeling approach combining process-based and morphology-based methods is proposed to reconstruct 3D models with diverse pore structure types.Then,the characteristics and differences in pore structure in these models are compared.Finally,the varia-tion laws and pore-scale mechanisms of the influence of pore structure on physical properties(permeability and elasticity)are discussed based on the reconstructed models.The relationship models between pore structure parameters and perme-ability/elastic parameters in the grain packing model are established.The effect of pore structure evolution on permeability/elasticity and the microscopic mechanism in three types of morphology-based reconstruction models are explored.The influence degree of pore structure on elastic parameters(bulk modulus,shear modulus,P-wave velocity,and S-wave veloc-ity)is quantified,reaching 29.54%,51.40%,18.94%,and 23.18%,respectively.This work forms a workflow for exploring the relationship between pore structures and petrophysical properties at the microscopic scale,providing more ideas and references for understanding the complex physical properties in porous media.

Petrophysical properties and their influencing factors of carbonates in the fourth member of Sinian Dengying Formation, Sichuan Basin, SW China

Based on the measurements of petrological, petrophysical and elastic properties of the samples of different sedimentary facies in the fourth member of Sinian Dengying Formation (Deng 4 Member) in the Sichuan Basin, the diagenetic processes of reservoirs of different sedimentary facies and their controls on the petrophysical properties were discussed. The results show that cracks and mineral composition jointly control the petrophysical properties, and both are significantly influenced by sedimentary environment and diagenesis. The microbial dolomite of mound-shoal facies mainly experienced multi-stage dolomitization, penecontemporaneous dissolution, tectonic rupture and hydrothermal/organic acid dissolution processes, giving rise to cracks and dissolved pores. The grannular dolomite of inter-mound-shoal bottomland or dolomitic lagoon facies mainly underwent mechanical compaction, burial dolomitization and tectonic-hydrothermal action, creating cracks and intercrystalline pores. The diagenesis related to crack development increases the pressure- and saturation-dependent effects of samples, leading to significant decrease in the compressional wave impedance and Poisson's ratio. Dolomitization changes the properties of mineral particles, resulting in a Poisson's ratio close to dolomite. The muddy, siliceous and calcareous sediments in the low-energy environment lead to the decrease of impedance and the differential change of Poisson's ratio (significantly increased or decreased). The samples with both cracks and dissolved pores show high P-wave velocity dispersion characteristics, and the P-wave velocity dispersion of samples with only fractures or pores is the lowest.

Reservoir quality evaluation using sedimentological and petrophysical characterization of deep-water turbidites:A case study of Tariki Sandstone Member,Taranaki Basin,New Zealand

The current study aims to ascertain the reservoir characteristics of the Tariki Sandstone Member of the Otaraoa Formation,Taranaki Basin,New Zealand.This study was carried out by integrating the comprehensive petrophysical evaluation,sedimentological and petrographic studies,as well as well log analysis by using data from six wells.The porosity-permeability relationship is used to divide the samples of the Tariki Sandstone Member into reservoir and non-reservoir facies.A thorough petrophysical analysis shows that the maximum porosity values fluctuate between 16.6%and 22.1%,while permeability ranges from 102 mD to 574 mD,which indicates fair to good reservoir quality.Moreover,the Tariki sandstone represents six hydraulic flow units with a high reservoir quality index and flow zone indicator representing good reservoir characteristics.The pore size varies between nano and megapores with dominant macropores.Based on the sedimentological and petrographic analysis,the Tariki Sandstone Member is classified as a combination of subarkose,arkose,and lithic arkose with fine to medium and moderately to moderately well-sorted grains.The main diagenetic factor affecting the reservoir quality is cementation,which occupied all the pores with calcite.On the bright side,the secondary pores are developed due to the dissolution of calcite cement and few grains.The well log analysis demonstrates the presence of low clay volume ranging from 0.3%to 3.1%,fair to good effective porosity values between 13.6%and 15.9%,net pay thickness from 18.29 m to 91.44 m,and hydrocarbon saturation from 56%to 77.9%.The findings from this study revealed that the Tariki Sandstone Member possesses fair to good reservoir quality and hydrocarbon potential,which indicate submarine fans as appealing hydrocarbon reservoirs.This study can be used in similar depositional environments elsewhere in the world.

Petrophysical characterization and 3D seismic interpretation of reservoirs in the Baris Field,onshore Niger Delta Basin,Nigeria

In order to evaluate the petrophysical properties,characterize the structural framework and determine the hydrocarbon in place of potential reservoirs in the Baris Field,onshore Niger Delta Basin,Nigeria,3D seismic and well log data from the field were collected and interpreted using Geographix and Petrel software.Two reservoir zones B2 and B5 were identified having porosity ranging from 21%to 22%,permeability from 235 to 523 mD and water saturation from 16%to 28%.Petrophysical parameters show that the two zones are good reservoirs and highly petroliferous.Seismic interpretation revealed the presence of six listric faults,two major faults(F1 and F2 trending in the northwestesoutheast direction)and four minor faults(F3,F4,F5 and F6).Faults 3,4 and 5 trend in the same direction as the major faults,while fault 6 trends in the northeastesouthwest direction.Two major horizons were identified,and they correspond to the two reservoir tops(B2_top and B5_top).Roll-over anticlinal structures between the two major listric faults were identified.The depositional environment of the Reservoirs B2 and B5 have been deciphered to be of a barrier bar or crevasse play and the trapping mechanism in the Baris Field is a four-way structural closure.STOOIP and GIIP for the two zones have been estimated with the zone B5 more prolific with a STOOIP and GIIP of 7.98MMSTB and 12.77MMMSCF respectively.

Evaluation of Hydrocarbon Reservoir in the “SIMA” Field of Niger Delta Nigeria from Interpretation of 3D Seismic and Petrophysical Log Data

3D seismic and petrophysical log data interpretation of reservoir sands in “SIMA” Field, onshore Niger Delta has been undertaken in this study to ascertain the reservoir characteristics in terms of favourable structural and petrophysical parameters suitable for hydrocarbon accumulation and entrapment in the field. Horizon and fault interpretation were carried out for subsurface structural delineation. In all, seven faults (five normal and two listric faults) were mapped in the seismic section. These faults were major structure building faults corresponding to the growth and antithetic faults in the area within the well control. The antithetic fault trending northwest-southeast and the normal fault trending northeast-southwest on the structural high in the section act as good trapping mechanisms for hydrocarbon accumulations in the reservoir. From the manual and auto-tracking methods applied, several horizons were identified and mapped. The section is characterized by high amplitude with moderate-to-good continuity reflections appearing parallel to sub-parallel, mostly disturbed by some truncations which are more fault related than lithologic heterogeneity. The southwestern part is, however, characterized by low-to-high or variable amplitude reflections with poor-to-low continuity. Normal faults linked to roll-over anticlines were identified. Some fault truncations were observed due to lithologic heterogeneity. The combination of these faults acts as good traps for hydrocarbon accumulations in the reservoir. Reservoir favourable petrophysical qualities, having average NTG, porosity, permeability and water saturation of 5 m, 0.20423, 1128.219 kD and 0.458 respectively.

Measurement and Analysis of Thermal Conductivity of Rocks in the Tarim Basin,Northwest China

As a parameter that describes heat transmission properties of rocks,thermal conductivity is indispensable for studying the thermal regime of sedimentary basins,and retrieving high-quality data of thermal conductivity is the basis for geothermal related studies.The optical scanning method is used here to measure the thermal conductivity of 745 drill-core samples from the Tarim basin,the largest intermontane basin with abundant hydrocarbon potential in China,and water saturation correction is made for clastic rock samples that are of variable porosity.All the measured values,combined with previously published data in this area,are integrated to discuss the distribution characteristics and major controlling factors that affect the thermal conductivity of rocks in the basin.Our results show that the values of thermal conductivity of rocks generally range from 1.500 to 3.000 W/m·K with a mean of 2.304 W/m·K.Thermal conductivity differs considerably between lithological types：the value of a coal sample is found to be the lowest as being only 0.249 W/m·K,while the values for salt rock samples are the highest with a mean of 4.620 W/m·K.Additionally,it is also found that the thermal conductivity of the same or similar lithologic types shows considerable differences,suggesting that thermal conductivity cannot be used for distinguishing the rock types.The thermal conductivity values of mudstone and sandstone generally increase with increasing burial depth and geological age of the formation,reflecting the effect of porosity of rocks on thermal conductivity.In general,the mineral composition,fabric and porosity of rocks are the main factors that affect the thermal conductivity.The research also reveals that the obvious contrast in thermal conductivity of coal and salt rock with other common sedimentary rocks can induce subsurface temperature anomalies in the overlying and underlying formations,which can modify the thermal evolution and maturity of the source rocks concerned.This finding is very important for oil and gas resources assessment and exploration and needs further study in detail.The results reported here are representative of the latest and most complete dataset of thermal conductivity of rocks in the Tarim basin,and will provide a solid foundation for geothermal studies in future.

One Dimensional Evolution Modeling of Source Rocks in the Chaluhe Basin, Yitong Graben

Chaluhe Basin is in Jilin Province of China with a cumulative sedimentary rock thickness of about 6000 meters and has four subdivisions: Wanchang Structural High, Bo-Tai Sag, Xinanpu Sag, Liangjia Structure High and the Gudian Slope. The basin with its better source rock distribution and more favorable maturation indicators than the adjacent Moliqing and Luxiang Basins is expected to be a potential hydrocarbon-producing basin. Four (4) wells were used in determining the maturation hydrocarbon generating potential of the mudstone beds present in the Eocene Formations (Shuangyang, Sheling and Yongji). Obtained result revealed heat flow average of 71.8 mW/m2, oil generation between 3.15 mg/g TOC and 39.49 mg/g TOC with gas generation of 6.98 mg/g TOC to 92.83 mg/g TOC. In conclusion the Eocene Shuangyang mudstone is the main petroleum source rock.

Review of Numerous Approaches for Unconfined Rock Compressive Strength Estimation

Most problems faced by practicing of the wellbore stability analysis involve evaluation of rock mechanical properties especially unconfined compressive strength(UCS) of formations,which is one of the major inputs for stability analysis models of the borehole.Different sources can be used to develop rock strength profile along the wellbore which is very essential to plan the mud weight window or bit selection for drilling operation.Using this

Two Dimensional Evolution Modeling of Source Rocks in the Chaluhe Basin, Yitong Graben

Yitong Graben in Jilin Province of China, hosts three basins, namely: Chaluhe, Luxiang and Moliqing basins. The Chaluhe basin, as the focal point of this study has five subdivisions, thus, Bo-Tai sag, Wanchang Structural high, Liangjia Structure high Xinanpu sag, and the Gudian slope, with a cumulative sedimentary rock thickness of about 6000 metres. The basin is supposed to be a potential hydrocarbon-producing basin with its better source rock distribution and more favorable maturation indicators than the adjacent Luxiang and Moliqing Basin. Determining whether the mudstone beds present in the Eocene Formations are matured enough to generate hydrocarbons, three (3) wells with Seismic Lines (clh02, clh05 and clh07) were used for the study. It is observed that the entire region from NW to SE in the source rocks is mature to produce oil and gas. At depths of about 2400 m and below show good maturity with vitrinite reflectance values averaging 1.02% Ro. The Eocene Shuangyang mudstone is the main petroleum source rock.

Depositional Setting and Petrophysical Evaluation of Reservoir of the K-Field in the Western Offshore Depobelt, Rio Del Rey Basin, Cameroon

The Rio Del Rey basin is a prolific petroleum field on the Continental margin of the gulf of Guinea and is one of the major producers in the gulf. The study was carried out using Schlumberger Petrel and Synergy Interactive Petrophysics software for the sequence stratigraphy and petrophysical analysis to study the depositional setting of the Rio Del Rey Basin, using Well Log Data. Five sequence boundaries, five Transgressive Surfaces and four Maximum Flooding Surfaces were identified from wireline log. The progradation of sediments is characterised by a number of stacked sequences deposited in a coastal complex, with offshore, shoreface, beach and tidal deposits. Sequence one contains mostly Lower shoreface deposits of fine to very fine laminated sediments. In sequence two there is, an increase proportion of upper shoreface deposits. Sequence three is dominated by upper shoreface and distributary channels deposits with a concomitant reduction of lower shoreface deposits while sequence four and five contain mostly stack distributary channels and beach deposits. The study has aided the identification and interpretation of two gas bearing and two oil bearing zones in the three wells based on hydrocarbon-typing using the sonic-resistivity logcombination. The total and effective porosities of the reservoirs range from 20% to 31% and 15% to 31% respectively, indicating that the reservoirs have very good porosities. The ratio of the net to gross thickness of the reservoirs is as high as 0.83. The water saturation values of the reservoirs ranges from 11% - 80%. The results of the petrophysical investigation show that the sand formations have good reservoir properties. The vertical facies succession records a migration/translation of laterally linked depositional environment, controlling reservoir properties like geometry, heterogeneity, porosity and permeability.