Reservoir Quality Evaluation Research Articles

Reservoir characterization of the Oligocene–Miocene siliciclastic sequences (Ghar Member of the Asmari Formation) in the northwestern Persian Gulf

This paper presents an integrated facies, diagenesis, and sequence stratigraphic analysis, and reservoir quality evaluation of the siliciclastic hydrocarbon reservoirs (Ghar Member of the Asmari Formation) in the NW Persian Gulf. Results of core descriptions, thin sections petrography, X-ray computed tomography (CT) scanning, X-ray diffraction, sieve analysis, porosity–permeability measurements, and petrophysical logs are used. Four petrofacies are recognized indicating deposition in shore-line (beach) sand bodies and supratidal to intertidal sub-environments. Calcite and anhydrite cementation, dolomitization, recrystallization, compaction, and fracturing are diagenetic processes which occurred in marine, hypersaline, and shallow burial realms. A large-scale transgressive–regressive sequence and five deepening-upward cycles are defined. Hydraulic flow units and pore-size classes are defined. The best reservoir units (hydraulic units 5 to 8 and pore-size classes 4 and 5) are formed within the well-sorted, rounded, and mature sand/sandstone facies in which intergranular pores are predominant and diagenetic imprints are negligible. These facies are located in lower-half of depositional cycles. Carbonate-dominated facies show variable reservoir properties depending on their diagenetic alterations. In these facies, dolomitization and fracturing improved the permeability. This study shows that reservoir properties of the Ghar Member are strongly facies-controlled and, therefore, are easily predictable within a sequence stratigraphic framework.

Reservoir quality evaluation as a measure to forecast hydrocarbon and CO2 storage prospects in Irati and Rio Bonito Formations, Paraná Basin

Enhanced hydrocarbon recovery processes coupled with CO2 storage are, by far, the cheapest carbon capture and storage (CCS) options in geological structures. However, reservoirs are also being explored for CO2 storage in regions without producing/depleted hydrocarbon reservoirs, such as the Irati and Rio Bonito Formations in the southwestern part of São Paulo. Therefore, the study involves petrophysics-based flow unit factors to predict the reservoirs’ quality, primarily focusing on hydrocarbon viability with CO2 storage possibilities based on the shale, carbonate, sandstone and siltstone rock units. The methodology involving the models for the research objective is uncommon for the Irati and Rio Bonito Formations. The porosity range is 0.02 to 0.15 in shales, 0.028 to 0.18 in siltstones, 0.03 to 0.21 in carbonates, and 0.10 to 0.31 in sandstones based on the sonic-density porosity (ФS-D) approach. Permeability (k) is 0.00005mD to 36.6mD in shales, 0.0008mD to 132mD in siltstones, 0.025mD to 786mD in carbonates and 8mD to 10000mD in sandstones. The results show more significant fluid transmission indices for the sandstone based on Ф, k, free fluid index-FFI, reservoir quality index-RQI, and flow zone indicator-FZI. Also, the parameters are considerably significant for carbonates in some instances, less effective for siltstone and comparatively insignificant for shale. However, shales` total organic content (TOC) values are up to 10.5%, suggesting their hydrocarbon generation potentials. Significant values (e.g., Ф ≥25% and FFI ≥20%) in sandstones indicate reservoirs with the potential for hydrocarbon accumulation. Considerable physical qualities, as presented for the sandstone, suggest reservoir rock units with reasonable fluid (e.g., gas) recovery and CO2 injection rates. Therefore, based on the research results, the Irati Formation shales are viable hydrocarbon source rocks, and the Rio Bonito Formation sandstones are potential hydrocarbon reservoirs. Subsequently, future hydrocarbon production events will enhance CO2 storage options in the region. Furthermore, the research results may serve as input data in related hydrocarbon exploration studies. However, if further research indicates non-commercially viable hydrocarbon reserves, the findings will also aid in delineating dedicated geological reservoirs for CO2 storage when needed.

Reservoir quality evaluation using petrophysical, well-log analysis and petrographical description: A case study from the Carboniferous-Permian Kulshill group formations, southern Bonaparte Basin, Australia

The Carboniferous – Permian Kulshill Group formations are producing reservoirs in the Petrel subbasin, Australia. The studied Keyling and Kuriyippi formations were investigated by integrating petrophysical, petrographical, sedimentological, and well-log interpretations. The petrophysical study reveals that both formations Keyling and Kuriyippi have very good porosity (max. 30.9% and 25.2% respectively) and permeability values (max. 3053 mD and 1025 mD respectively) indicating good reservoir quality. Based on petrographic descriptions, both formations comprise very fine to coarse-grained sandstone and moderate to well-sorted with abundant intergranular porosity. Many diagenetic factors acting on the reservoir quality of the Kulshill Group formations are observed. Cementation and clay minerals as well as secondary porosity is more visible in both formations while at the same time the formations still holding good enough reservoir quality.The interpreted well-log data indicate that the Kuriyippi Formation is mostly oil bearing, whereas the Keyling Formation is water bearing reservoir. The average petrophysical parameters of both formations show that porosity values reaching up to 16.5–32.3% respectively, and clay volume up to 25.2% with abundance of montmorillonite, mixed clay layers, while glauconite, micas, and illites were found in few amounts in both formations. The hydrocarbon saturation recorded higher values (up to 80.4%) in the Kuriyippi Formation while the measured values in the Keyling Formation is less and the water saturation is always playing around the cutoff values. This can be attributed to the presence of the permeability barrier Treasury shale Formation underlying the high quality Keyling sandstone reservoir blocking the upward migration of hydrocarbon.

Reservoir quality evaluation and prediction in ultra-deep tight sandstones in the Kuqa depression, China

Core, thin sections, cathodoluminescence (CL), scanning electron microscopy (SEM), conventional well logs and image logs are used to unravel depositional microfacies, diagenetic facies and fractures in the deeply buried (6000–8100 m) Cretaceous Bashijiqike (K1bs) and Baxigai (K1bx) Formations in Kuqa depression of the Tarim Basin. Results show that depositional microfacies in core and well log data include distributary channel, river mouth bar and distributary bay deposits of fan-braided delta fronts as well as lacustrine deposits. We establish well log predictable models of depositional microfacies using conventional and image logs. The Cretaceous sandstones experienced low to medium mechanical compaction and low intensity dissolution. Dominant diagenetic minerals are carbonate cements, clay minerals and minor amounts of quartz cements. The pore spaces are primarily intergranular pores and rare dissolution pores. We identify three diagenetic facies according to compaction state and diagenetic minerals, including carbonate cemented facies, tightly compacted facies, and facies having limited compaction and lacking cement (slightly cemented and compacted facies). We use well log characteristics to interpret diagenetic facies in areas without core data. Fractures are also elements of reservoir quality, including vertical opening-mode fractures, high to medium dip angle fractures, low angle fractures that probably include small faults and horizontal fractures. Fractures include open, partially open, and closed (sealed) fractures. We used image logs to identify fracture attributes, and calculate fracture density, porosity, aperture, and length. Depositional microfacies and diagenetic facies determine the primary intergranular pores and diagenesis subsequently modified secondary pore spaces. Natural fractures acted as both reservoir porosity (probably less than 1%) and as hydrocarbon flow channels accounting for elevated permeability. We evaluate and predict reservoir quality by superposing depositional microfacies, diagenetic facies and fracture occurrence.

Fractal-Based Approaches to Pore Structure Investigation and Water Saturation Prediction from NMR Measurements: A Case Study of the Gas-Bearing Tight Sandstone Reservoir in Nanpu Sag

Pore space of tight sandstone samples exhibits fractal characteristics. Nuclear magnetic resonance is an effective method for pore size characterization. This paper focuses on fractal characteristics of pore size from nuclear magnetic resonance (NMR) of tight sandstone samples. The relationship between the fractal dimension from NMR with pore structure and water saturation is parameterized by analyzing experimental data. Based on it, a pore structure characterization and classification method for water-saturated tight sandstone and a water saturation prediction method in a gas-bearing sandstone reservoir have been proposed. To verify the models, the fractal dimension from NMR of 19 tight sandstone samples selected from the gas-bearing tight sandstone reservoir of Shahejie Formation in Nanpu Sag and that of 16 of them under different water saturation states are analyzed. The application result of new methods in the gas-bearing tight sandstone reservoir of Shahejie Formation in Nanpu Sag shows consistency with experimental data. This paper has facilitated the development of the NMR application by providing a non-electrical logging idea in reservoir quality evaluation and water saturation prediction. It provides a valuable scientific resource for reservoir engineering and petrophysics of unconventional reservoir types, such as tight sandstone, low porosity, and low permeability sandstone, shale, and carbonate rock reservoirs.

Integration of geoscience data to delineate quality of the Asmari reservoir, Iranian part of the Persian Gulf basin

The Hendijan Field is an asymmetric structure located in the northwestern Persian Gulf and consists of several oil and gas-bearing intervals. Oligocene to Miocene successions in the field host large volumes of hydrocarbons. The Asmari Formation comprises the mixed siliciclastic and carbonate members formed in a shallow marine carbonate ramp depositional environment. The siliciclastic part displays the best reservoir quality within the Asmari Formation. Through petrophysical, sedimentological, and geophysical analysis, this study divides the Asmari Formation into six, third-order depositional sequences. By doing so, it clarifies the relationships between depositional sequences and reservoir characteristics, particularly porosity and water saturation. Detailed petrographical analysis, core description, well log analysis, and seismic interpretation distinguish eight microfacies, two petrofacies, and six third-order sequences within the Asmari Formation. 3D reservoir-property models are developed that incorporate elements of the sequence stratigraphical framework. Within the six identified sequences, high reservoir quality zones are associated with AS-4 and AS-5, which comprise mostly grain-supported lithologies associated with shoal facies. The supratidal, intertidal, and lagoonal facies of AS-2, which are often associated with the occurrence of anhydrite and mud-supported fabrics, reflect lower reservoir quality. Hydraulic flow units (HFU) are delineated to assist in characterizing reservoir heterogeneity and porosity/permeability prediction. Five HFU were identified by applying the flow-zone-indicator method to evaluate reservoir quality. Both the transgressive system tract (TST) of AS-2 and early TST plus late highstand system tract (HST) of AS-6 contain elements of HFU-A. The most productive units of AS-4 and AS-5 belong to HFU-E.

Evaluation of depositional environments and reservoir quality of sediments in “OLI” field, offshore, Niger Delta, Nigeria

Evaluation of depositional environments and reservoir quality of sediments in “OLI” field, offshore, Niger Delta, Nigeria

Quantitative evaluation of reservoir quality of tight oil sandstones in chang 7 member of Ordos Basin

In order to establish a quantitative evaluation system for reservoir quality suitable for tight oil sandstones, in this study, taking the Chang 7 Member in the Maling area of the Ordos Basin as an example, the nuclear magnetic resonance, clay mineral analysis, high pressure mercury injection analysis and logging interpretation technology have been used to carry out a comprehensive evaluation of the pore structures, sand body structures and oil-bearing properties of tight oil sandstone reservoirs. The results show that the pseudo-capillary pressure curves transformed by the NMR T2 spectra are consistent with the capillary pressure curves measured by the core experiments. This method can be used for accurate characterization of the pore structures of the reservoir. The pore structure parameters calculated based on the pseudo-capillary pressure curves can accurately reflect the pore structures of the reservoirs such as micropores-thin throats and complex tortuosity. At the same time, the smoothness feature of conventional logging curves is used to evaluate the sand body structures and heterogeneity of the reservoir, and the apparent energy storage coefficient is introduced to quantitatively evaluate the oil-bearing properties of tight oil reservoirs. The evaluation results are in good agreement with the actual production situation. The larger the apparent energy storage coefficient, the higher the initial output of the oil wells. The evaluation results of the reservoir quality of the tight oil sandstones constructed in this paper are highly consistent with the production status, so the method has broad application prospects.

Characterization of crude oil charging of Xiaoerbulake dolomite in the Tarim basin: Insights from bitumen distribution

Understanding hydrocarbon charging mechanisms is essential for reservoir quality evaluation. In this study, a systematic investigation of micro-nano scale oil charging characteristics in the Lower Cambrian Xiaoerbulake Formation of the Tarim Basin was performed via mercury intrusion capillary pressure (MICP) on samples of four types of dolomitic lithofacies before and after bitumen removal. Additionally, to determine the pore structure and space that was occupied by the bitumen, a series of observations using both optical and field-emission scanning electron microscopy (FE-SEM), along with micro-computed tomography (micro-CT) were conducted. A combination of these micro-CT and MICP techniques enabled us to determine how bitumen is distributed in micro-nano pore space of the bulk sample. Imaging results show that three types of pores (intergranular pores, intercrystalline pores and intragranular pores) and microfractures are developed within these lithofacies and confirmed that bitumen has occupied pores >20 nm in diameters. Furthermore, a relationship between pore-throat threshold and charging force was established under the reservoir conditions. It was found that the oil charging force and pore-throat threshold are different for each lithofacies with the microbial dolomites demonstrating the highest charging force and smallest pore throat threshold; as a consequence, they are the most favorable lithofacies for the accumulation and migration of oil and gas which should be considered for future exploration efforts in dolomitic reservoirs.

Constraints on Diagenetic Fluid Source and Genesis in Tight Dolostone Reservoir of Submember Ma55 of Ordovician Majiagou Formation in Northwestern Ordos Basin, China: Evidence from Petrology and Geochemistry

Diagenetic fluids is one of the most important reservoir modifiers, their differences can result in various petrography, storage capacity, and geochemical characteristics, so clarifying the diagenetic fluids is vital for understanding dolostone origin. Dolomitization is an important genetic type of dolostone reservoir, the fluid properties differ in different dolomitization, which may lead to reservoir storage capacity changes. Therefore, the identification of dolomitization fluid properties is critical for deeply understanding of dolomitization process and predicting storage capacity. Two types of dolostone are developed in submember Ma55 of Majiagou Formation in northwestern Ordos Basin, with obviously different petrological characteristics and reservoir properties. On the basis of petrological studies such as core and casting thin section observation and cathodoluminescence analysis, the diagenetic fluid properties of these two dolostone are characterized by geochemical analytical methods such as major and trace element tests. The results show that Type-1 dolostone is mainly composed of micritic dolomite, showing micritic structure and algae-rich lamina structure, and accompanied by evaporite minerals and moldic pores. This type of dolostone has a various Mn content, weak to medium cathodoluminescence intensity, high contents of TiO2, Al2O3, K2O+Na2O, Li, and U, and lower content of TFe2O3. The type-2 dolostone is composed of fine-grained dolomite with obvious residual texture of primary limestone, clear brim, and cloudy center structure, accompanied by the existence of intergranular pores. Most of this kind of dolostone have medium-strong cathodoluminescence, higher TFe2O3 content and lower TiO2, Al2O3, K2O+Na2O, Li, and U contents. Moreover, both the two types of dolostone have similar Fe/Ca and Mn/Ca ratios, and a low and concentrated CaO content, whose composition is similar to that of stoichiometric dolomite. The comprehensive analysis shows that the diagenetic fluid of Type-1 dolostone is mainly a high salinity fluid existed in plaster and calcareous sediments in a near surface environment with low temperature. The diagenetic fluid of Type-2 dolostone may be a high salinity brine formed by evaporation and concentration of seawater with normal salinity. The research results will provide a significant theoretical basis for the evaluation of dolostone reservoir quality and the prediction of favorable areas of reservoir distribution.

Impacts of mineralogy and pore throat structure on the movable fluid of tight sandstone gas reservoirs in coal measure strata: A case study of the Shanxi formation along the southeastern margin of the Ordos Basin

Movable fluid content and permeability are important reference factors for reservoir quality evaluation and recovery enhancement. In this study, based on multiple experimental results, 10 typical samples from a tight sandstone gas reservoir in the coal measure strata of the Shanxi Formation along the southeastern margin of the Ordos Basin were divided into three lithofacies to discuss the factors influencing movable fluid content and permeability. The results show that the fluid has a strong seepage capacity and a high degree of mobility in relatively large pore throats. The relatively large pores in the study area are secondary dissolved pores of various origins. High quartz and feldspar contents are conducive to the formation of secondary pores, while the presence of carbonate minerals and clay minerals play an inhibitory role. The pore throat size range of 0.05–0.1 μm is the critical interval for the conversion of bound fluid to movable fluid. The movable fluid saturation and movable fluid porosity are affected by submicron- and micron-scale pore throats of >0.1 μm, while the permeability is controlled by micron-scale pore throats sizes of >1 μm. The volumetric proportion of the relatively large pore throats is influenced by the mineralogical composition of the rock, the size of the pore throats, and the degree of sorting, which further control the amount of moveable fluid and its percolation capacity. The highest movable fluid content and permeability appear in the massive gravel-bearing coarse to medium sandstone lithofacies (Lm) with a high proportion of submicron- and micron-scale pore throats, whereas the lowest occurs in parallel bedding or ripple laminations，medium to fine sandstone lithofacies (Lpr) with a high proportion of nano-scale pore throats. The lithofacies with cross bedding and medium sandstone (Lc) is also dominated by nano-scale pore throats, which shows the characteristics of low movable fluid content and medium permeability due to the retention of some micron-scale pore throats. This study describes the mobility of fluids with different pore throat sizes in detail and determines the pore throat size range corresponding to the transition from bound fluid to movable fluid, which can provide a reference for the evaluation of movable fluid seepage in other regions.

Quantitative evaluation of unconsolidated sandstone heavy oil reservoirs based on machine learning

Classification and evaluation of reservoirs conforming to geological characteristics are the proposed premises of the high‐quality development of unconsolidated sandstone heavy oil reservoirs. The P oilfield in Bohai Bay is one of the largest offshore oilfields in China, but the reservoirs are highly heterogeneous, have complex pore structures, and change fluid properties, which make the classification of reservoirs very difficult. At present, the most commonly used reservoir classification methods are based on the results of logging interpretation, which cannot eliminate the constraints of linear relationships such as empirical formulas. Machine learning has significant advantages for identifying reservoir classification problems that are complex and nonlinear with geological characteristics. First, this study fully considered the pore structure and fluid properties and selected four representative evaluation parameters. An improved K‐means method was used to establish a reservoir classification evaluation system. Characteristics, such as the sedimentary microfacies, pore structure and oilfield production performance, of different types of reservoirs were then analysed. Finally, six logging curves were selected as input results, reservoir classification was used as an output result, and XGBoost was used to carry out reservoir classification evaluation for the entire area. The accuracy of XGBoost was 85.35%. Furthermore, XGBoost was compared with three other machine learning methods to confirm its reliability. The results showed that the reservoirs in the study area can be divided into three types. Sandstone thickness and pore structure were the most important parameters that affected reservoir quality. Among various machine learning algorithms, XGBoost can accurately and quickly achieve a quantitative evaluation of reservoir quality.

Fracture characterization based on improved seismic amplitude variation with azimuth inversion in tight gas sandstones, Ordos Basin, China

Fractures are essential for gas accumulation in tight sandstones, as they enhance reservoir permeability and provide migration paths for fluid transport. The presence of fractures facilitates the formation of fracture networks during hydraulic fracturing and, therefore, is important for effective development of tight gas sandstones. Accordingly, predicting fracture distribution could provide insight into the reservoir quality of tight gas sandstones. Seismic amplitude variation with azimuth can evaluate the properties of vertical fractures embedded in tight sandstone. This study proposes an improved inversion scheme based on azimuthal amplitude differences to compute anisotropic parameters for fracture characterization by incorporating rock physics relationships. Our proposed method improves the robustness of the anisotropic parameter estimates by removing the effect of the isotropic background using azimuthal amplitude difference data obtained after evaluating fracture strikes. Theoretical modeling and real data analysis illustrated the enhanced sensitivity of the azimuthal amplitude differences to the anisotropy related to fractures. Real data applications indicated that the predicted fracture strikes coincide with the results estimated by tectonic stress field analysis. The computed fracture density correlates with logging permeability, implying considerable influence from fractures on permeability improvement in tight sandstones. Further analysis indicated that the gas production capacity of tight sandstones is affected simultaneously by fractures and gas enrichment. Accordingly, an integrated indicator is proposed to evaluate reservoir quality, that simultaneously considers the degree of fracture development quantified by the fracture density, and gas enrichment represented by rock compressibility. The proposed indicator is correlated positively with comprehensive reservoir properties defined by the cumulative sand layer thickness, porosity, gas saturation, and permeability, providing a reliable and practical pointer to identify favorable areas in tight gas sandstones.

Diagenetic controls on the reservoir quality of Neogene sandstones in the offshore area of the Bengal Basin, Bangladesh

The Neogene sandstones offer hydrocarbon reservoirs in the offshore area of the Bay of Bengal (Bangladesh), but their reservoir quality is not well known. Understanding the impact of depositional and diagenetic controls on reservoir quality is crucial to hydrocarbon exploration and production in reservoir sandstones. This study aims to investigate the depositional and diagenetic controls on reservoir quality of the Neogene Surma Group from the Sangu Gas Field (the only offshore gas field), in the Bay of Bengal, Bangladesh using a combination of petrographical, petrophysical, X‐ray diffraction, scanning electron microscope fitted with energy dispersive spectra and core analysis data. Diagenetic modifications to the sandstones include mechanical and ductile grain compaction followed by clay cementation (dominantly chlorite, illite–smectite and minor kaolinite), poikilotopic calcite cement and subordinate amounts of quartz cement, as well as partial dissolution of feldspars and lithic fragments. Sandstones with primary porosities ≥20% have average intergranular volume value of 33%, although permeability in most sections of the reservoir falls below 8–10 mD. There has also been localized creation of secondary porosity due to dissolution. The average intergranular porosity lost by compaction is 14% (ranges from 3% to 37%), and the average porosity lost by cementation is 10% (ranges from 3% to 37%). This study shows that the reservoir quality is predominantly controlled by depositional environment (ductile grain supply, clay content), a diagenetic processes (compaction followed by clay cement and early to intermediate poikilotopic calcite cement) and will provide insights into the reservoir quality evaluation in the offshore areas of the Bengal Basin.

Formation Evaluation of Lower Goru Sands of Khipro Block, Lower Indus Basin, Pakistan

Formation evaluation is widely used in exploration and production in order to minimize the risk, uncertainty, and understanding of the detailed characteristics of potential reservoir rocks. This study is aimed to evaluate the Petrophysical characteristics of upper and lower basal sands of the Cretaceous lower Goru Formation in Niamat-01 and Siraj-01 wells and to focus on hydrocarbon exploration potential. These wells have been drilled in the Khipro block, lower Indus basin, which is the least explored for the reservoir quality evaluation. Present study characterized the lower Goru sands of the Khipro block. It is interpreted that the thickness of upper and lower Basal sands are 13m and 10m, respectively in Naimat Basal 01, whereas 9m and 17m, respectively, are reported in SirajSouth-01. The average effective porosity is 11% in upper Basal sands while 26% is interpreted for lower Basal sand in Naimat Basal-01. An average porosity of 11% is found for upper Basal sands in Siraj South-01 and 11% for lower Basal sand. Water saturation (Sw) calculated for upper and lower Basal sands are 22% and 19%, respectively. The hydrocarbon saturation (Sh) of 78% is interpreted for upper Basal sands and 81% hydrocarbon saturation reported for lower Basal sands in Naimat basal-01. However, 36% and 45% Sw have been recognized for upper and lower Basal sands, respectively. Whereas hydrocarbon saturations of 64% and 55% are reported for the upper and lower basal sands, respectively, in SirajSouth-01. Crossover effects in front of targeted formations confirmed the presence of hydrocarbons in the zone of interest. Lower sands of the lower Goru Formation in the Khipro block are favorable for hydrocarbon production and have potential for future hydrocarbon exploration activities.

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.

An intelligent approach for reservoir quality evaluation in tight sandstone reservoir using gradient boosting decision tree algorithm

Abstract This article focuses on the study of identifying the quality of tight sandstone reservoirs based on machine learning. The machine learning method – Gradient Boosting Decision Tree (GBDT) algorithm is used to design and classify reservoir quality. First, it is based on logging data, core observation, cast thin section, and reservoir physical statistics. The permeability, porosity, resistivity, mud content, sand-to-ground ratio, and sand thickness were preferred as reservoir evaluation criteria in the area, and the gray correlation method was used to obtain reservoir quality categories and construct training datasets. The machine learning GBDT algorithm is used to train and test the obtained dataset. It is found that the recognition accuracy of the GBDT model is 95% by confusion matrix analysis. In addition, it is compared with four commonly used reservoir prediction methods (Bayesian discriminant method, random forest, support vector machine, and artificial neural network) for verifying the reliability of the GBDT model. Finally, the GBDT model is used to identify the reservoir quality of the study area, and it is well verified in the production data. The research results show that the GBDT model can become an important tool for rapid and real-time tight sandstone reservoir evaluation.

Characterization of kerogen in shale core plugs using T2*-based magnetic resonance methods

Kerogen assessment is essential to evaluation of shale reservoir quality. Routine analysis techniques are sample destructive and time-consuming. 1H magnetic resonance (MR) methods offer a fast, robust, and non-destructive alternative. However, kerogen MR signal detection and quantification is challenging due to its short signal lifetime and requires new MR methods. In this work, the T1-T2* relaxation correlation method was investigated for assessment of kerogen in shales. Step pyrolysis experiments were conducted coupled with MR T1-T2* relaxation correlation measurements and thermogravimetric analysis (TGA). The results show that the short relaxation lifetime signal observed in the shale samples was dominated by the kerogen species. The shale signal was resolved in the T1-T2* relaxation correlation measurement that was calibrated to report kerogen, oil, and water 1H content of the shale samples. Kerogen 1H content was then used to evaluate the hydrocarbon generation potential of kerogen. An elemental balance analysis was conducted to estimate the kerogen chemical evolution in the Van Krevelen diagram. The results proved that a simple FID measurement was adequate to resolve and quantify the kerogen signal component in shales.

Comparative study on pore structure characteristics of marine and transitional facies shales: A case study of the Upper Permian Longtan Formation and Dalong Formation in the Lower Yangtze area, south China

The Permian shale reservoir in the Lower Yangtze area of South China is regarded as a target with a high potential for shale gas exploration. To investigate the pore structure characteristics and evaluate reservoir quality, 32 shale samples from the Upper Permian Longtan Formation and Dalong Formation in the Lower Yangtze area were studied using a suite of techniques including total organic carbon (TOC) content, X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), nitrogen (N2) and carbon dioxide (CO2) gas physisorption, mercury injection capillary pressure (MICP), petrographic observations, and fluid inclusion analysis. Petrographic observations reveal that the Longtan Formation is rich in vitrinite and inertinite, while the Dalong Formation contains a large amount of solid bitumen. Primary organic pores (POPs) are the original cellular pores that develop in inertinite. Vitrinite particles did not show visible pores. Solid bitumen infills fractures and occupies the interparticle (interp) space between the mineral grains in the Dalong Formation. A small number of speckled secondary organic pores (SOPs) were observed in the solid bitumen with diameters less than 10 nm. Both the TOC and quartz contents exhibit negative relationships with the pore volumes (PVs) for the Longtan and Dalong Formations, owing to the poor development of pores in the organic matter (OM) and occlusion of most mineral pores by migrated bitumen. There is a positive relationship between clay minerals and PVs owing to the sheet-like meso-pores and macro-pores in the clay minerals. The evolution of organic porosity is related to the differences in maceral composition and thermal maturity. Thermal cracking of residual oil and bitumen and the expulsion of gaseous hydrocarbons contributed to the formation of SOPs in marine shales. In contrast, vitrinite and inertinite in gas-prone shales do not display noticeable morphological changes across the entire thermal evolution process, owing to their low hydrocarbon generation potential.

An Unsupervised Clustering Method for Selection of the Fracturing Stage Design Based on the Gaussian Mixture Model

In order to further improve the efficiency and economic benefits of multi-stage fracturing of unconventional oil and gas horizontal wells, it is urgently needed to conduct comprehensive reservoir quality evaluation research on the whole horizontal well section. Firstly, based on logging data, focusing on reservoir quality and completion quality, and comprehensively considering key factors such as reservoir physical property indexes and fracability indexes, a subjective and objective coupled evaluation model of the entropy weight method (EWM) and the analytic hierarchy process (AHP) without bias is established to obtain the composite reservoir quality index. Then, unsupervised gaussian mixture model (GMM) clustering algorithms are used to classify the reservoir comprehensive quality index and finally four grades of fracturing stages are established. Taking shale oil well A and B of the Permian Lucaogou Formation in Jimsar Sag, Junggar Basin, as examples, the comprehensive reservoir quality evaluation and clustering model training, testing, and prediction were carried out. By comparing the clustering results with the actual fracturing stages and oil production, it is found that the evaluation results obtained by the GMM clustering algorithms based on the coupled evaluation model of EWM and AHP can identify the good fracturing grades. The algorithm can also predict the fracturing grades of other wells in the same block. It proves the accuracy of the method proposed in this paper and provides a favorable technical basis for determining the placement of multi-cluster fracturing perforation.