Reservoir Accumulation Research Articles

Delaminated Fracturing and its Controls on Hydrocarbon Accumulation in Carbonate Reservoirs of Weak Deformation Regions: A Case Study of the Yuanba Ultra-Deep Gas Field in Sichuan Basin, China

Since the discovery of the Yuanba gas reservoir, there has been no unified conclusion of hydrocarbon accumulation. The Feixianguan Formation micrite and argillaceous limestone are controversial as the direct cap rock. This research analyzed the integrity of the limestone layer from delaminated fracturing to judge whether it can be as the caprock and then discuss the mechanism of accumulation. Delaminated fracturing and its controls on hydrocarbon accumulation were studied using seismic data, well logging data, rock mechanic measurements, and petroleum geological data. Mudstones from the Upper Permian Wujiaping Formation serve as the source rock. Changxing Formation dolomite from the Upper Permian is the reservoir rock. The caprock is marlites from the Lower Triassic Feixianguan Formation. The Changxing Formation had middle-high dip angle fractures formed by integrating pore fluid pressures and the tectonic stresses in the Late Triassic Indosinian Movements. The Feixianguan Formation had horizontal stylolites and fewer fractures, which kept the Feixianguan Formation marlites good caprocks. The adjacent Feixianguan and Changxing formations have their fracture system known as delaminated fractures. As a result, the Upper Permian Changxing Formation dolomite has good reservoir properties, while the Lower Triassic Feixianguan Formation limestone or marlites have good capping performance. These delaminated fractures are formed because of different lithologies and thicknesses in the carbonate rock series. It is the key factor in controlling the formation of Yuanba Gas Field with weak deformation. Delaminated fracturing suggests a significant exploration potential in carbonate strata with weak deformation, particularly in ultra-deep areas.

Geometry, formation mechanisms, and hydrocarbon exploration significance of Pishan Caldera, Tarim Basin, northwest China

The discovery of an oil reservoir in Pishan Caldera of the Tarim Basin, northwest China, highlights the hydrocarbon exploration potential of large calderas. We used 3 D seismic interpretations, waveform clustering analysis, and seismic profiles to investigate the origin and evolution of Pishan Caldera, along with the mechanisms of hydrocarbon accumulation, and its significance for future oil and gas exploration. Pishan Caldera is located at depths of >7000 m, has an elliptical shape, extends over an area of 25 × 20 km, and is surrounded by ring faults. Pishan Caldera were the result of magma withdrawal and later magma intrusion. Volcanic eruptions, caldera collapse, and reactivation of Pishan Caldera resulted in Cretaceous oil migration and accumulation in Cretaceous breccia reservoirs. Ring faults, dense fracture networks, and lava tubes associated with the caldera acted as conduits for upward hydrocarbon migration. We propose a generalized model for hydrocarbon reservoirs related to the caldera, which includes five major reservoir types: drape anticline, fault block, volcanic-trapped, laterally sealed and lava tube type. Further efforts should be made to identify deep caldera structures that may be targets for hydrocarbon exploration.

Evaluation of gas-rich “sweet-spot” and controlling factors of gas–water distribution in tight sandstone gas provinces: An example from the Permian He8 Member in Sulige Gas Province, central Ordos Basin, Northern China

The objective optimization of the gas-rich “sweet-spot” is the key to efficient exploration of tight sandstone gas reservoirs. However, research on evaluating the gas-rich “sweet-spot” based on the controlling factors and models of gas–water distribution of tight sandstone is limited. The sand bodies of the Permian He8 Member in Sulige Gas Province of the Ordos Basin are fluvial-delta distributary channels; the gas reservoir porosity dominantly ranges from 6% to 12%, with an average of 8.78%, and exhibits the permeability of (0.1–1) × 10–3 μm2, with a median of 0.38 × 10–3 μm2. The gas reservoirs are tight lithologic lens type with no edge and bottom water, showing a large-area quasi-continuous distribution with horizontal contiguous and vertical multi-layer superposition. Formation water related to the reservoir accumulation process is classified into paleo-formation water, paleo-condensate water, and present-condensate water. The controlling factors of gas production via the source rock and reservoir conditions exhibit distinct stages. The relationships between gas production and the source rock Ro, HGI, reservoir porosity, and permeability are positive, when gas production is <1 × 104 m3/d. However, it can be controlled by a combination of factors when gas production is >1 × 104 m3/d. Formation water production is related to a low HGI, poor physical reservoir properties, large sandstone thickness, excessive fracture development, and gaseous water condensation. Three gas–water distribution models of the gas-rich, moderate gas-rich, and complex gas–water types were established because of the accumulation conditions and gas test results in different areas. The gas-rich type (water-poor gas reservoir) is represented by the Suzhong, Sudong-I and Sudong-III areas, moderately gas-rich type (water-less gas reservoir) is distributed in the Sunan area, and gas–water complex type (water-rich gas reservoir) is mainly distributed in the Suxi-I, Suxi-II, and Sudong-II areas. Based on the analyses of the high weighted parameters of the controlling factors, the values of the gas reservoir comprehensive evaluation index (F) for commercial gas well area, low production gas well area, and gas-containing well area were >31, 26–31, and <26, respectively.

Random noise attenuation via convolutional neural network in seismic datasets

With the explosive growth in seismic data acquisition and the successful application of convolutional neural networks to various image processing tasks within multidisciplinary fields, many researchers have begun to research convolutional neural networks based seismic interpretation techniques. Seismic random noise attenuation is a key step in seismic data processing. In seismic data interpretation, faults are an important geological structure that has great significance for accumulation and migration of oil and gas reservoirs. Random noise within seismic data will seriously affect the accuracy of subsequent data processing and interpretation. Therefore, it is crucial to eliminate random noise in seismic data. This paper aimed to improve the Signal-to-Noise Ratio of seismic data, and proposed an intelligent convolutional neural network noise reduction framework. In this paper, the median filtering, the mean filtering, and the proposed algorithm is used to denoise seismic fault data. Experimental results show that the method not only yields a higher Signal-to-Noise Ratio, but also preserves more useful fault information.

Shale gas characterisation for hydrocarbon accumulation and brittleness by integrating a rock-physics-based framework with effective reservoir parameters

Efficient exploration and development of shale gas require the identification of reservoirs with abundant hydrocarbon accumulation and high brittleness. However, realistic descriptions and seismic visibility of these reservoir properties have not been thoroughly investigated due to the complex elastic responses of organic shale. This study develops a new rock-physics-based framework incorporated with proposed effective reservoir parameters to evaluate hydrocarbon accumulation and brittleness in shale gas reservoirs. The developed rock physics model quantitatively relates the elastic characteristics of organic shale to the controlling factors of gas enrichment and brittleness that are realistically represented by the proposed effective reservoir parameters. Moreover, the rock physics template (RPT) computed using the proposed model represents a powerful tool to reveal implicit correlations between the effective reservoir parameters and elastic attributes in organic shale. In a real data application related to the Longmaxi shale gas reservoir in the Sichuan Basin, the constructed RPT provides reliable estimates of effective reservoir parameters using seismic-inverted elastic attributes, with the results being validated by logging data from gas-producing wells. Furthermore, reservoir classification based on the RPT and effective reservoir parameters offers a practical way to identify geological and engineering sweet spots, yielding valuable insights into reservoir qualities associated with gas enrichment and brittleness for locating promising shale gas areas. The predicted results indicate that high-quality shale gas reservoirs exhibit a structure-related distribution with potential geological significance.

Lithologic Hydrocarbon Accumulations in the Upper Jurassic Kalazha Formation in the Foreland Slope, the South Marginal Junggar Basin, Northwest China

The foreland slope in the south marginal Junggar Basin (SMJB) is geologically favorable for mass lithologic oil and gas reservoir accumulation. Based on outcrops, thin sections, individual-well facies, and cross-well stratigraphic correlation, the stratigraphic distribution and features of the Upper Jurassic Kalazha Formation were investigated in the SMJB. There are two sedimentary sources in the southwest and southeast Kalazha Formation, which thin out from south to north and vanish in the northern slope. Fan deltas occur in the southwest, and braided river deltas occur in the southeast. Kalazha reservoir rocks and sedimentary facies were predicted using joint 2D and 3D seismic impedance inversion. According to the overall analysis, the Kalazha Formation in the foreland slope is favorable for hydrocarbon accumulation, considering structural highs as the destination of long-term hydrocarbon migration and the updip wedge-out zone in the north with potential lithologic traps. The accumulation model was established with source rocks, reservoir rocks, caprocks, and migration systems for the lithologic hydrocarbon reservoirs in the Kalazha Formation in the SMJB. As per the model and regional stratigraphic and structural features, Kalazha lithologic hydrocarbon reservoirs mainly formed in the annular updip wedge-out zone in the foreland slope. Our deliverables may provide useful information for mass lithologic hydrocarbon accumulation in the foreland slope and deep to ultra-deep hydrocarbon exploration in the SMJB.

Discharging Sediment Downstream: Case Studies in Cost Effective, Environmentally Acceptable Reservoir Sediment Management in the United States

AbstractSediment accumulation in reservoirs across the world diminishes reservoir benefits, increases maintenance costs, and damages the environment. United States regulatory policy requires State ...

Occurrence morphology of bitumen in Dengying Formation deep and ultra-deep carbonate reservoirs of the Sichuan Basin and its indicating significance to oil and gas reservoirs

Abundant bitumen can be discovered in the wells of Upper Sinian Dengying Formation in the Sichuan Basin and their peripheral outcrops sections. As the cracking product of a paleo-oil reservoir, the occurrence morphologies and distribution characteristics of bitumen in carbonate reservoirs can indicate the preservation, migration and other key information of (paleo-) oil and gas reservoirs. In order to provide reference and basis for the deep and ultra-deep oil and gas exploration in the Sichuan Basin and the basins in western China, this paper systematically studies the occurrence morphological characteristics of bitumen in deep and ultra-deep carbonate reservoirs in well Gaoshi 1 of the Sichuan Basin by carrying out thin section observation, scanning electron microscope-energy spectrum analysis and fluid inclusion organic geochemical analysis on the cores of the fourth member of Dengying Formation (Deng 4 Member). In addition, the coupling relationship between the occurrence morphology of bitumen and the key event of hydrocarbon accumulation is revealed. And the following research results are obtained. First, solid bitumen in the Deng 4 Member deep and ultra-deep reservoir has two types of occurrence morphology. The first type of bitumen adheres to pore walls in the shape of a rim or exists in pores in the form of sticky branch (e.g., Wells Chuanshen 1 and Gaoshi 1). There are more obvious shrinkage fractures and residual pores generated by in-situ thermal cracking in this type of bitumen. And combined with fluid inclusion and burial thermal history, it can effectively indicate that a paleo-gas reservoir has been preserved so far since the paleo-oil reservoir was thermally cracked into carbonaceous bitumen. The second type of bitumen is distributed in intra- and inter-neogenic mineral crystals in pores disorderly in the shape of grain and band (e.g., Wells Mashen 1 and Wutan 1) and it has obvious breaking edges. It reveals that after a paleo-oil reservoir was thermally cracked into carbonaceous bitumen, the paleo-gas reservoir suffered blowdown and gas escape and neogenic fluid minerals moved into reservoirs to fill in pores. In conclusion, the occurrence morphologies and distribution characteristics of bitumen in deep and ultra-deep carbonate reservoirs can effectively indicate the hydrocarbon accumulation and evolution process of paleo-oil and gas reservoirs.

Assessment of phosphorus loading dynamics in a tropical reservoir with high seasonal water level changes

Nutrient accumulation in man-made reservoirs has been documented worldwide. Therefore, quantifying phosphorus loading and understanding its temporal dynamics in reservoirs is mandatory for sustainable water management. In this study, the Vollenweider's complete-mix phosphorus budget model was adapted to account for high water level variations, which are a common feature in tropical reservoirs, and for internal phosphorus loads. First- and zero-order kinetics were adopted to simulate phosphorus settling and release from the sediment layer, respectively, considering variable area of phosphorus release according to the height of the anoxic layer. The modeling approach was applied for a 52-months period to a 31-years-old reservoir located in the semiarid region of Brazil with 7.7 hm3 storage capacity. The simulations were supported by hydrological, meteorological and water quality data, as well as analyses of phosphorus partitioning of the reservoir bed sediment. The external phosphorus load was estimated from a relationship adjusted between inflow and phosphorus concentration, revealing an u-shaped pattern. Sedimentary phosphorus linked to iron and aluminum (PFeAl) increased over time and along the reservoir. Such measurements were used to estimate the internal phosphorus load, i.e., the yield from the bed sediments to the water column. The adaptations proposed to the model's structure improved its capacity to simulate phosphorus concentration in the water column, from “not satisfactory” to “good”. We estimate that the internal phosphorus load currently accounts for 44% of the total load. It prevailed during the wet period, when reservoir stratification and hypolimnetic hypoxia were more notable, resulting in higher phosphorus concentration in the water column due to the combined effects of internal and external loadings. However, if the reservoir were 70 years older, the internal load would reach 83% of the total and the reservoir would become a source instead of a sink of phosphorus.

Geochemistry and sources of hydrate-bound gas in the Shenhu area, northern south China sea: Insights from drilling and gas hydrate production tests

Research on the origin and source of hydrate-bound gas and its relationship to deep conventional oil and gas accumulation in a basin is critical to understanding the accumulation mechanism of gas hydrates and to resource evaluation of gas hydrate accumulation. In this study, the hydrate-bound gas obtained via pressure coring and the production gas recovered during a production test on a gas hydrate reservoir in the Shenhu area offshore of Southern China were tested and discussed. The geochemical analysis results indicate that methane is the predominant gas, and heavier hydrocarbons (C2+) are also present but in low concentrations. The molecular compositions of the hydrate gas recovered from two production test sites are similar to those of the hydrate-bound gas acquired via pressure coring. In addition to the isotopic composition of the methane, the carbon and hydrogen isotopes of the C2+ hydrocarbons were obtained for the first time. The δ 13 C isotopes of the methane range from −66.6‰ to −46.2‰, indicating that the hydrate-bound gases have a mixed origin, containing both biogenic and thermogenic gases. The plot of δ 13 C 1 versus δ 13 C 2 suggests that the biogenic and thermogenic hydrocarbons were derived from marine organic matter and terrestrial organic matter, respectively. The isotopic characterization of the hydrate-bound gas reveals that the thermogenic hydrate gas contains both humic-type gas and sapropel-type gas, but the sapropel-type gas is predominant. The source rocks of the thermogenic hydrate gas are interpreted to be both the gas-prone coal measure strata of the Enping Formation and the oil-prone medium-deep lacustrine strata of the Wenchang Formation, the latter of which contributed more to the hydrocarbon supply of the gas hydrates. In addition, the maturity of the source rocks of the thermogenic hydrate gas may be lower than that of the deeply buried conventional hydrocarbons discovered in the Baiyun Sag-Panyu Low Uplift area. The seismic profile crossing the shallow gas hydrate accumulations and deep conventional gas reservoirs clearly shows that the proven LW3-1 thermogenic gas reservoir communicated with the gas hydrate stability zone through vertical migration pathways formed by high-angle faults and gas chimneys. This indicates that there was a cogenetic relationship between the thermogenic hydrate gas and the deep conventional hydrocarbon reservoir, which was supplied the thermogenic gas derived from both the Wenchang and Enping formations. The major implications of this finding are that it confirms, rather than theorizes, the identity of the hydrocarbon source rocks of the thermogenic hydrate gas in the Shenhu area for the first time, and it demonstrates the coupling relationship between the shallow gas hydrate accumulations and the deep conventional reservoirs proposed in previous studies. The mechanisms of hydrocarbon migration and gas hydrate accumulation in the production test gas hydrate reservoirs in the Shenhu area were also identified, providing a valuable reference for subsequent exploration and for the potential exploitation of gas hydrate reservoirs in the South China Sea. • The δ 13 C and δD isotopes of the heavier hydrocarbons (C2+) in the Shenhu area are obtained for the first time. • The origin of the hydrate gas obtained from the second trial production well in the Shenhu area is confirmed. • The hydrocarbon source rocks of the thermogenic hydrate gas in the Shenhu area are identified. • Coupled paragenetic relationship between shallow gas hydrate and deep petroleum system is revealed.

Evaluation of balneability index data of the main beaches of the metropolitan region of Belém, Pará, Brazil in the july 2016/2021 period

Water is a natural resource with great importance and diverse purposes of use; however, it is a limited resource. The beaches are dynamic environments, composed of sandy soils and sediment deposits caused by wave action, for this reason due to this mobility provides protection to the coast by the infl uence of waves. The beaches located in the Metropolitan Region of Belém - RMB, are considered estuarine beaches, due to the affl uence of the Guajará Bay and rivers of the Amazon. To evaluate the data of the bathing indices of the main beaches of the Metropolitan Region of Belém, PARÁ, BRAZIL in the period July 2016/2021. This is a quantitative study of descriptive analysis of data obtained from the agencies responsible for the analysis and dissemination of monitoring of the balneability of the beaches of the Metropolitan Region of Belém - RMB. An Excel table (Microsoft Excel 2016) was composed. In 2016, three beaches showed inconsistency in the results, being classifi ed as unsuitable for bathing, and these were the beaches of Baía do Sol, Amor and Cruzeiro, located respectively in the Districts of Mosqueiro, Outeiro and Icoaraci. This was the only year in which the two beaches located in the districts of Mosqueiro and Outeiro were classifi ed as unsuitable, in the period from 2016 to 2021, unlike Praia do Cruzeiro, in the District of Icoaraci, which presented problems in the years 2016, 2018, 2019 and 2020. Suggesting possible exacerbated anthropic activity at the site, improper sewage dumping or infl ow from other rivers. Urbanization, large tourist infl ux in certain months of the year, improperly dumped sewage, and rainfall may be preponderant factors in the accumulation of organic matter and reservoirs of parasites, viruses, and various enteric diseases. It can be concluded that the main beaches of the Metropolitan Region of Belém - RMB analyzed in this study, based on the data obtained by SEMMA, showed compliance with the legislation about monitoring, analysis, collection, environmental education, and dissemination of data to the population. Except for Cruzeiro Beach, in the District of Icoaraci, which showed non-compliance in the months of July in four years between 2016 and 2021.

A ResNet-Based Method for Complex Channel Interpretation in Seismic Volumes

Channels usually contribute to the accumulation of reservoirs and their identification is useful in the well placements for mining and oil field development. We consider the task of channel detection as a regression problem and propose a workflow to identify the channels in seismic volumes with complex structures using an end-to-end 3D convolutional neural network. To train the network, we automatically generate a training dataset containing more than 19000 3D synthetic seismic volumes and the corresponding channel labels, which are shown to be sufficient to train our network. Although only trained on the synthetic dataset, the network can automatically learn informative features for channel identification. Multiple synthetic and field applications show that the network can accurately and efficiently separation all the channel reflections in 3D seismic volumes with complex structures. With a NVIDIA P100 GPU, the predicting application takes only 0.6 hours for a 10GB seismic volume with size 1201×1601×1351.

Prediction of favorable areas for oil accumulation in outer-source tight reservoirs under the control of lateral migration distance: A case study of the Baikouquan Formation, Mahu Sag, Junggar Basin, China

There is a starting pressure gradient (SPG) for oil migration in tight reservoirs (TRs), and the SPG and the migration force jointly control the migration distance of oil. The key factor of oil accumulation in the tight glutenite reservoir (TGR) of the Lower Triassic Baikouquan Formation (T1 b) in the Mahu Sag is whether the oil can be laterally charged into the TRs. To analyze the lateral migration distances of oil in TRs and predict the favorable accumulation areas for oil, we have carried out a physical simulation experiment of oil charging on glutenite reservoirs of T1 b for obtaining the SPG of oil migration and knowing the relationship between SPGs and the reservoirs’ physical property. According to the basin simulation, we have obtained the pressure evolution of the source-rock formation as well as reservoir formation and the physical property evolution of the reservoir. Finally, we have predicated the favorable oil accumulation areas through calculating the distribution characteristics of SPGs as well as the theoretical distances of lateral migration of oil during the key oil accumulation period and considering the theoretical distance of the lateral migration of oil as the main controlling factor. Our results suggest that there is a SPG in the TGR of the T1 b and that there is a power function relationship between the SPG and the permeability. The theoretical lateral migration distance of oil in T1 b during the key oil accumulation period was the farthest in the northern sag, which was gradually shortened to the east, west, and south. In class I favorable areas, the reservoirs have good physical properties where overpressure has developed; in addition, the lateral migration distance of oil is far. Therefore, these are the most favorable areas for oil accumulation.

Unlocking the Potentials of Helium in Nigeria

With the dwindling price of crude oil globally and its negative consequences on the economy and environment, there is an urgent need to diversify in the search for alternative sources of revenue for the country particularly in the Oil and Gas sector.&nbsp; The discovery of radiogenic helium in commercial quantity serves to augment the gross domestic product of any nation due to the various roles it plays in our everyday life; from entertainment to the medical field, where it is used for cooling superconducting magnets in medical Magnetic Resonance Imaging (MRI) scanners and Nuclear Magnetic Resonance (NMR) spectrometers to industrial applications as an agent for in maintaining controlled atmosphere and in detecting leakages. It is also useful in supersonic wind tunnels because of its stability, thermal and caloric perfect nature as well as its high speed of sound and high heat capacity ratio. Just recently, it was discovered that helium is being used to create hard drives in computers. Helium has no known substitution in cryogenic uses. It is obvious that there is a great need for the indigenous sourcing of this valued resource which is non-renewable. The discovery of large quantities of helium in Tanzania has heightened the search for this noble gas in Nigeria.&nbsp; This paper is therefore aimed at reviewing the generation, migration and reservoir accumulation of the gas from both biogenic and abiogenic sources.in order to support and likewise make vital contribution towards sourcing for helium in Nigeria.

Quantitative analysis of fracture evolution in fold: Insights from FDEM modelling

Fractures associated with buckle folds play a vital role in hydrocarbon migration and accumulation in reservoirs. However, the prediction of fracture initiation and propagation during buckle folding is technically challenging. In this study, a series of buckle folds with different initial geometries, which represent different deformation stages of folds, are simulated to study the fracturing mechanism during buckling. To obtain a better understanding of the progressive fracturing process, a 2D modelling approach using an improved combined finite-discrete element method (FDEM) is utilized. The influence of fold geometries with significant influence on fracture development are considered, including layer thickness and wavelength. The results show that the development of fractures can be directly observed through the improved FDEM modelling. It is concluded that the development and distribution of major fracture sets are different at various periods during the evolution history of the fold. Tensile fractures initiate more easily in tighter folds, while shear fractures develop more easily in gentle folds. The pressure from the overburden or the constrains of the surrounding rock is critical for the developments of fractures at hinges. As the fold becomes tight, the density of fractures decreases, whereas the length of single fractures increases. The results further show that the layer thickness and wavelength are vital for the initiation and propagation of major fracture sets. In summary, the FDEM modelling approach can well explain most of the fracture sets occurring in the buckle fold. This study has provided a deeper insight into the fracture evolution in fold.

Hydrocarbon accumulation depth limit and implications for potential resources prediction

The horizontal distribution and periodic accumulation of hydrocarbon in reservoirs are well understood. However, our understanding on the vertical distribution of hydrocarbon accumulation in reservoirs is not clear and remains mysterious to some extent. We proposed a concept of hydrocarbon accumulation depth limit (HADL) to characterize the hydrocarbon’s vertical distribution in petroliferous basins, which is determined by statistical analyses of the variation trends of reservoir layers’ essential properties, including hydrocarbon saturations (So), movable hydrocarbon ratios (Mo) and dry layer ratio (Ko), when the depth is increased. A total of 80,762 drilling results from 12,237 exploration wells in six representative petroliferous basins in China were collected and analyzed. The reservoir layers’ essential properties So, Mo and Ko and their correlations with porosity, permeability, pore throat radius and thermal evolution degree were investigated. The critical values of So, Mo and Ko that define HADL were quantified to be So = 0, Mo = 0 and Ko = 100. Our study indicates that the HADL in petroliferous basins varies from less than 3,000 m to more than 13,000 m deep, depending on the hydrocarbon composition, reservoir lithology, reservoir age, geothermal gradient, tectonic movement, etc. Two factors play an essential role in the formation and variation of HADL: 1) the depletion of hydrocarbon generation potential of source rocks which cuts off hydrocarbon contribution for reservoirs formation and 2) the termination of differential compaction which eliminates capillary pressure difference between the outer surrounding rocks and inner reservoir layers, ending the dominant driven force for hydrocarbon migration and accumulation in deep and tight reservoir layers. All proven oil reserves of 33.95 billion tons equivalent in China, as well as world’s discovered 52,926 oil and gas reservoirs and their unproved potential resources, are distributed above the HADL we defined.

Diagenetic controls on reservoir quality of a mixed carbonate-siliciclastic system: Sycamore Formation, Sho-Vel-Tum Field, Oklahoma, USA

Reservoir quality (RQ), commonly related to diagenesis, is important to predict formation porosity and permeability. The lack of studies to understand the role of diagenesis on tight reservoirs is a limiting factor for predicting petroleum accumulation in unconventional reservoirs. This study aims to determine the influence of diagenesis on RQ for the mixed carbonate-siliciclastic Sycamore Formation in southern Oklahoma. Additionally, this study assesses other geologic factors such as depositional facies control on diagenesis of the Sycamore.Petrographic observation, geochemical data, and conventional plug analysis from six cores and one outcrop were used to accomplish three objectives: i) reconstruct the paragenetic sequence; ii) determine the role of diagenesis on RQ; and iii) elucidate geological factors that control the diagenetic evolution in the Sycamore strata.Four facies were identified: Massive Calcite-cemented Siltstones, Massive Calcareous Siltstone, Bioturbated Mudstones, and Argillaceous Mudstones. However, this study focuses on the siltstones and their associated diagenetic processes and products. Porosity evolution in the siltstones is affected by cementation and dissolution processes. These diagenetic processes are related to each other; calcite cement decreases permeability during early diagenesis and controls the flow of later diagenetic fluids responsible for feldspar dissolution. Additionally, differences in the supply between a carbonate and siliciclastic material and a change from a carbonate-dominated system to a mixed system through time controls the distribution of calcite cement in the Sycamore.This study allows geologists to understand the diagenetic evolution and to characterize RQ of the Sycamore and similar formations by considering the sediment supply between carbonate- and siliciclastic-dominated systems, changes in stratigraphy, and influx of acidic fluids. Identifying geological controls on diagenesis and defining the influence of diagenesis on RQ in tight formations is important for the exploration and development of unconventional reservoirs, to build predictable porosity and permeability models, and to identify petroleum accumulations.

Evolution of a deeply-buried oil reservoir in the north Shuntuoguole Low Uplift, Tarim Basin, western China: Insights from molecular geochemistry and Re–Os geochronology

The recently discovered Shunbei Oilfield is perceived as a remarkable breakthrough in deep marine carbonate petroleum exploration in the Tarim Basin, western China. Constraining the absolute timing of petroleum system evolution is crucial for further hydrocarbon exploration and development in the area. Here, we integrated molecular geochemical correlation, stable carbon isotopes of bulk oil (bitumen) and Re–Os geochronology to trace the petroleum sources, to constrain the absolute timing of hydrocarbon generation, and to reconstruct the petroleum system evolution of the deeply-buried oil accumulations in carbonate reservoirs. Biomarker parameters derived from isoprenoids, terpanes, steranes and aromatic compounds, as well as stable carbon isotopic compositions, revealed that the Ordovician reservoir oils and bitumens were all originated from the same source rock, deposited under a highly-reduced environment with organic matters being predominantly contributed by algae and bacteria. The calculated equivalent vitrinite reflectance (Rc) values of reservoir bitumen and oil samples indicate that the Shunbei Oilfield has experienced at least two hydrocarbon charges. Geochemical characteristics and thermal maturity suggest that the bitumen within the Ordovician Yijianfang Formation reservoirs in the north Shuntuoguole Low Uplift is not originated from thermal cracking, thermochemical sulfate reduction, biodegradation, nor gas washing. Re–Os isotopic data from six reservoir bitumen samples yield an isochron age of 399 ± 12 Ma with an initial 187Os/188Os ratio (Osi) of 1.26 ± 0.11. This age is interpreted to represent the timing of oil generation when compared with the thermal evolution of possible source rocks and other radiometric dating results in the region. A comparison of 187Os/188Os of the 399 Ma-old bitumen and that of possible source rocks at the time of oil generation suggests that the reservoir oil was possibly originated from the lower Cambrian Yuertusi source rock. This work highlights that Re–Os geochronology combining with the initial 187Os/188Os ratio can be used to effectively constrain the timing of hydrocarbon generation in petroleum systems with complex tectonic history, multiple oil charges and alterations.

Physical property and hydrocarbon enrichment characteristics of tight oil reservoir in Chang 7 division of Yanchang Formation, Xin'anbian oilfield, Ordos Basin, China

Xin'anbian Oilfield of the Ordos Basin is the large tight oilfield to be first exploration discovery in china. The production of tight oil increased significantly in recent years. It shows great exploration potential of Chang7 tight oil. But the physical property and hydrocarbon enrichment characteristics of Chang 7 tight oil reservoirs were rarely studied, The forming conditions of tight oil reservoirs are systematically summarized and analyzed through the study of hydrocarbon generation, sedimentary reservoirs and hydrocarbon migration and accumulation based on production and core experimental data. The result shows that, The porosity of the Chang 7 2 reservoir mainly distributed in 5.0–11.0%, average at 7.9%, The permeability mainly distributed in 0.04–0.18 × 10 −3 μm 2 , average at 0.12 × 10 −3 μm 2 , The pore diameters of the tight oil reservoir distributed in 2–8 μm. The high-quality Chang 7 3 source rocks and the micropsammite of Chang 7 2 subaqueous distributary channel were widely distributed in the study area. The lenticular or banded sand bodies are distributed among mudstone or hydrocarbon source rocks and have the advantage of migration distance for hydrocarbon accumulation. The reservoir space is composed of micro-nanometer pores and throat, that is formed in the process of increasing pressure during hydrocarbon generation and hydrocarbon accumulation. The Chang 7 tight oil was generated in the early Cretaceous and injected into the sand of the subaqueous distributary channel driven by continuous hydrocarbon generation supercharging. The formation and accumulation of tight oil reservoirs are mainly controlled by source rocks, sedimentary microfacies and reservoirs of good quality.

Accumulation and Distribution of Natural Gas Reservoir in Volcanic Active Area: A Case Study of the Cretaceous Yingcheng Formation in the Dehui Fault Depression, Songliao Basin, NE China

Tight gas sandstone and volcanic gas reservoirs have received global attention in the energy arena for further exploration and exploitation attempts. Considering the Yingcheng Formation of Dehui fault depression in the Songliao Basin as an example, this study focused on the accumulation and distribution of natural gas reservoirs in volcanic area in a fault depression basin. Volcanic activities occurred in the Yingcheng Formation, which is distributed centrally in the northwest of the study area. During the sedimentation of the Yingcheng Formation, fan-delta, lacustrine, and nearshore subaqueous fan facies were deposited. The source rocks of the Yingcheng Formation have high abundance of organic matter mainly in type III at high-overmature stages, indicating favorable conditions for gas production. The porosity of volcanic reservoir is 3.0%-14.8%, the permeability is 0.0004 mD-2.52 mD, and the pore types are mainly secondary dissolved pores and fractures. Besides, the porosity of the tight sandstone reservoir is 0.5%-11.2%, and the permeability is 0.0008 mD-3.17 mD. The pore types are mainly interparticle pores, with a small proportion of intraparticle pores and microfractures. The intrusion of late volcanic magma provided sufficient heat for the thermal maturity progression of organic matter in Yingcheng Formation and promoted the generation of natural gas in large quantities. Volcanic rocks formed at the early and middle stages of volcanic activities occupied the sedimentary space and hindered the development of sedimentary sand bodies to a certain extent. However, volcanic rocks can become the seal to promote the formation of tight sandstone gas traps. Comparing tight sandstone reservoirs with volcanic ones, the latter are less affected by compaction; thus, their petrophysical properties do not vary much with depth, showing more homogeneous characteristics. The pyroclastic rocks influenced by volcanic activity and the secondary pores formed by dissolution in the later stages also provide reservoir space for gas accumulation. Ultimately, the tight sandstone and volcanic rocks in the study area form a complex gas reservoir system, which can become a reference for exploration and exploitation of natural gas in other petroliferous fault depressions that are affected by volcanisms.