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Prediction of Formation Pressure Based on Numerical Simulation of in Situ Stress Field: A Case Study of the Longmaxi Formation in the Nanchuan Area, Eastern Chongqing, China
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Lower Paleozoic dark shale is developed in the western Middle Yangtze Block, which lays a material foundation for the enrichment and accumulation of marine shale gas. In order to ascertain the control action of geological structures on the differential preservation of shale gas and reveal the key factors in shale gas preservation, this paper firstly analyzed the structure characteristics of this area, carried out structure pattern recognition and structural belt division, and studied structural deformation mode and intensity. Based on this, the relationships between different structure styles and shale gas preservation conditions were analyzed. Finally, combined with the structural deformation and the lithofacies paleogeographic characteristics of marine shale, the favorable exploration zones of shale gas were proposed. And the following research results were obtained. First, the western Middle Yangtze Block can be divided into four structural deformation belts, and three types of piggyback structural patterns have been identified, including restricted type, weakly reformed type and strongly reformed type. Second, the restricted type is located in the northwestern part of Hunan and Hubei Provinces. In this pattern, piggyback structure is incomplete and thrust belt and Compressive fold belt are developed. Third, the weakly and strongly reformed types are located in the western parts of Hunan and Hubei, and Wulingshan area, respectively. They both have complete piggyback structures, but the former has lower deformation intensity and has never undergone the late superimposed reformation. Fourth, there are three structural transfer belts in the western Middle Yangtze Block, i.e. the structural transfer belt between the East Sichuan fault–fold belt and West Hunan–Hubei fault–fold belt, the structural transfer belt between West Hunan–Hubei fault–fold belt and Wulingshan fault–fold belt, and the structural transfer belt between the outcrop and the hinterland of Middle Yangtze Block. The first one is structurally transformed at the Qiyueshan fault. The East Sichuan fault–fold belt on the west is an ejective fold with low fault density and formation denudation intensity, where shale gas is enriched in anticlines and slopes; while the West Hunan–Hubei fault–fold belt on the east is a trough-like fold with strong faulting and high formation denudation intensity, where shale gas is enriched in residual synclines. In conclusion, shale gas preservation conditions of Upper Ordovician Wufeng Formation–Lower Silurian Longmaxi Formation in this area are the best in Zigui syncline, thrust–detachment zone and western margin of Qiyueshan fault. The favorable exploration areas of shale gas of Lower Cambrian Niutitang Formation are distributed in the western flank of Yichang Slope, Kaixian thrust zone, compressive fold zone and thrust–detachment zone.
Poor reservoir physical property which leads to low rate of water injection pressure decline after the shut-in because of drilling control is the main characteristic of Daqing peripheral oilfields. To reduce reservoir energy loss, ensure the effect of infilling well, it is necessary to study the formation pressure of infill well point. However, there is no formation pressure prediction formula for infill well point in low permeability reservoir. In this article, combined with detailed reservoir description results, the effective characteristics of formation with different permeabilities are analyzed, the range of effective displacement permeability are defined, and the formation pressure of infill well point is calculated based on reservoir engineering method. Meanwhile, according to the actual injection pressure, produced liquid volume and partial static pressure data, numerical simulation pressure prediction is presented to simulate infill well point pressure. Considering to both prediction results, formation pressure at infill well point can be determined. Field test verifies that the predicted pressure is close to the actual pressure with an error rate within ± 10%, wells with pressure coefficients less than 1.80mpa/100m can be drilled, and those with the pressure coefficients greater than 1.80mpa/100m, drilling should be processed after depressurization.
We process rigorously GPS data observed during the past 25 years from continental China to derive site secular velocities. Analysis of the velocity solution leads to the following results. (a) The deformation field inside the Tibetan plateau and Tien Shan is predominantly continuous, and large deformation gradients only exist perpendicular to the Indo‐Eurasian relative plate motion and are associated with a few large strike‐slip faults. (b) Lateral extrusions occur on both the east and west sides of the plateau. The westward extrusion peaks at ~6 mm/yr in the Pamir‐Hindu Kush region. A bell‐shaped eastward extrusion involves most of the plateau at a maximum rate of ~20 mm/yr between the Jiali and Ganzi‐Yushu faults, and the pattern is consistent with gravitational flow in southern and southeastern Tibet where the crust shows widespread dilatation at 10–20 nanostrain/yr. (c) The southeast borderland of Tibet rotates clockwise around the eastern Himalaya syntaxis, with sinistral and dextral shear motions along faults at the outer and inner flanks of the rotation terrane. The result suggests gravitational flow accomplished through rotation and translation of smaller subblocks in the upper crust. (d) Outside of the Tibetan plateau and Tien Shan, deformation field is block‐like. However, unnegligible internal deformation on the order of a couple of nanostrain/yr is found for all blocks. The North China block, under a unique tectonic loading environment, deforms and rotates at rates significantly higher than its northern and southern neighboring blocks, attesting its higher seismicity rate and earthquake hazard potential than its neighbors.
Micro pore structure of shale has attracted much attention, which can be discussed based on the improved classical model. The Longmaxi shale is as research object. The results show the TOC ranges from 0.50% to 2.65%, equivalent reflectance is between 2.22% and 2.75%, and clay mineral content ranges from 23.7% to 35.4%. The porosity and total surface area are between 1.77% and 3.69%, 26.67 m²/g and 38.46 m²/g, respectively. Volume and surface area of micro-pores are primarily determined by the diameter, less than 10 nm. Meso-pores are more likely to develop in organic particles. The morphology of pores is in cylindrical and parallel-plate shape. The improved BET model can be utilised to calculate dimensions and surface area of the micro-pores. The D-R equation usually overestimates the volume of the micro-pore. The H-J model and carbon black model by the V-T method verify the effectiveness of the improved BET model.
The effect of controlling strata movement in solid filling mining depends on the filling rate of the goaf. However, the mechanical property of the overburden in the backfill stope and the designed size of the backfill mining workface should also be considered. In this study, we established a main roof strata model with loads in accordance with the theory of key strata to investigate the stability of the overburden in solid dense filling mining. We analyzed the stress distribution law of the main roof strata based on elastic thin plate theory. The results show that the position of the long side midpoint of the main roof strata failed more easily because of tensile yield, indicating that this position is the area where failure is likely to occur more easily. We also deduced the stability mechanics criterion of the main roof strata based on tensile yield criterion. The factors affecting the stability of the overburden in solid dense filling mining were also analyzed, including the thickness and elasticity modulus of the main roof strata, overlying strata loads, advanced distance and length of workface, and elastic foundation coefficient of backfill body. The research achievements can provide an important theoretical basis for determining the designed size of the solid dense filling mining workface.
The use of high-resolution borehole imaging is thus shown to produce a more reliable assessment of in-situ stress orientation. The authors therefore recommend that the higher resolution of such imaging tools should therefore be treated as a de-facto standard for assessment of in-situ stress orientation prior to rock testing. Use of borehole imaging should be formally instituted into best practice or future regulations for assessment of in-situ stress orientation prior to any hydraulic fracturing operations in the UK.
The Wufeng Formation–Longmaxi Formation in the Sichuan Basin in South China is the key stratum for shale gas exploration and production. To date, three national shale gas demonstration zones have been developed. Nevertheless, there are still some test wells that have not yet been commercialized. In this study, the geological characteristics of commercial and non-commercial zones are analyzed, as are the main controlling factors of high-producing wells (high estimated ultimate recovery; EUR), and the reasons for low-production wells (low EUR) by dissecting the three national shale gas demonstration zones and the main shale gas exploration wells. The results of this study indicate the following: (1) The black shale in the WF2–LM4 graptolite zone is deposited in the Craton depression on the Upper Yangtze plate, which provides a relatively stable tectonic environment for tectonic deformation and uplift destruction. The large shale thickness and weak tectonic activity jointly result in shale gas being enriched mainly in the deep-water shelf. (2)The regional fault has a destructive effect on shale gas preservation, and the shale gas reservoir is likely to be destroyed. In the areas close to the regional fault, multiple fracture-fluid migration activities caused by multistage tectonic movements are also detrimental to shale gas preservation. Conversely, shale gas is generally well preserved in areas far from regional faults. (3) The black shale thickness in the WF2–LM4 graptolite zone in the deep-water shelf area controls the shale gas field distribution. Furthermore, the horizontal well trajectory in the WF2–LM4 graptolite zone determines the shale gas well test production and EUR. The results of this work will provide a reference for shale gas exploration and development of the Wufeng Formation–Longmaxi Formation in the Sichuan Basin, as well as the Silurian strata in other parts of the world.
Measurements of in situ stress in a single well from borehole breakouts, hydraulic fracturing, multipole acoustic logs and differential strain analysis of core indicate that the orientation of the maximum horizontal stress is northwest-southeast in thick channel-fill sandstones in the central-western Bonan Oilfield, while the orientation is northeast-southwest in the thin interbed siltstones and mudstones of the floodplain in the eastern Bonan Oilfield. This result shows that the orientation of the maximum horizontal stress in the thin interbed of siltstones and mudstones is in accordance with the regional stress orientation obtained by the focal mechanism of a natural earthquake, but has a 30°–40° variation with the thick channel-fill sandstones. Finite element simulation suggests that the main reason for the variation in the orientation of the maximum horizontal stress is the diversity of overall mechanical properties, especially modulus of elasticity, of the thick channel-fill sandstones and the interbedded thin layer of siltstones and mudstones. The average Young's modulus over the stratigraphic column governs stress rotations. The transformation of the orientation of the maximum horizontal stress from the central-western to the eastern locations is at the channel boundary. This research provides a case in which the variation in the orientation of the maximum horizontal stress is affected by thick channel-fill sandstones. It shows that lithological changes can cause variations in the direction of in-situ stress.
Abstract: In situ stress is crucial for hydraulic fracturing during enhanced coalbed methane (CBM) recovery. The study is an attempt to get a better idea of fine evaluation of the stress distribution, and to clarify the stress distribution near the fault zone. The in situ stresses and formation pore pressure of coal seams at depths of 300-1300 m in the Zhengzhuang area of the southern Qinshui Basin were systematically analysed using well test data. The research area was divided into three partitions based on formation pore pressure gradient and regional geological structure, the three partitions present various petrophysical properties. Moreover, a 3D simulation was conducted to evaluate the effects of faulting on the stress state. Excellent relations exist among the pore pressure, minimum horizontal stress (Po and σh) and depth of the target coal seam, which can be used to predict the distribution of in situ stresses in the research area where few well test data exist. A lower lateral stress coefficient (κ) suggests a higher permeability in extensional basin. Lower horizontal tectonic stress coefficients and relative stress factors suggest a higher permeability area. The simulation and microseismic fracture monitoring results show that the horizontal principal stress direction obviously changes near the fault zone, suggesting the existence of a complex in situ stress state. Faulting has a great influence on σH orientation. The stress simulation could be a means to detect faults and predict the direction and magnitude of σH for areas without adequate well test data. Therefore, these results may have significant implications for the permeability evaluation of coal seams during safety mining and CBM production.
Keywords: Coal reservoir; in situ stresses; permeability; pore pressure; tectonic stress coefficient
Natural fractures serve as significant storage spaces for hydrocarbons and are favorable for fluid flow in shale gas reservoirs; therefore, predicting the intensity and distribution of natural fractures within reservoirs are of extreme significance for shale gas exploration and development. Natural fractures in the Nanchuan region are generally in high dip angles, and the dominant fracture strikes are in the ∼NE-SW and ∼NW-SE directions. Most natural fractures within the Longmaxi Formation are formed in the Late Yanshanian period. Therefore, in this study, the Late Yanshanian paleotectonic stress field was numerically investigated. The comprehensive rupture rate (CRR) was defined and calculated as an indicator to quantitatively predict the intensity and distribution of natural fractures within the Longmaxi Formation. The results indicated that regions with well-developed fractures were mainly located in/around fault zones and fold zones, among fault/fold orientations change, and at fault tips. The intensity and distribution of natural fractures in the Longmaxi Formation of Nanchuan region were influenced by many factors including tectonic activities, mineral compositions, etc. The present study provides preliminary insights into natural fractures within the Longmaxi Formation of Nanchuan region, South China, which can guide and support shale gas exploration and development.
Knowledge of the present-day in-situ stress state has significant applications in the exploration and development of tight gas reservoirs. The Ahe Formation is an important tight gas reservoir in the Dibei Gasfield of Kuqa Depression. However, prior to this study, little attention has been paid to the present-day in-situ stress field within the formation. In the present study, the in-situ stress orientation and magnitudes were investigated based on well log calculations and geomechanical modeling. The horizontal maximum principal stress (SHmax) orientation was determined from interpretations of drilling-induced tensile fractures (DITFs) and borehole breakouts in imaging logs, which showed variations between NNW-SSE-trending and NNE-SSW-trending in the Dibei Gasfield. The in-situ stress magnitudes were calculated in four wells based on well logs, the results indicated a normal faulting stress regime within the Ahe tight gas reservoir. Numerical simulation of the present-day in-situ stresses showed that the magnitudes of vertical stress (Sv), SHmax and horizontal minimum principal stress (Shmin) were −105.5 MPa∼-191.0 MPa, −88.9 MPa∼-142.9 MPa, and −79.1 MPa∼-127.7 MPa within the Ahe Formation, respectively. In addition, considering the present-day in-situ stress state in the Ahe Formation of Dibei Gasfield, natural fractures in directions parallel/sub-parallel to the SHmax orientation with high fracture angles showed great contributions to subsurface fluid flow. Borehole instability may become a potentially significant problem when drilling vertical wells and horizontal wells deviated toward the SHmax orientation in the Ahe tight gas reservoir of Dibei Gasfield.
In-situ stress is a vital index on the coal reservoir permeability and coalbed methane (CBM) development. Based on 41 sets of well test data at depths (h) of 353–1273 m in Fanzhuang-Zhengzhuang Block, the distribution of in-situ stress was analyzed systematically and its effect on coal permeability was also addressed. Results show that stress fields could convert in the vertical and four ranges corresponding to the certain depth can be characterized: the σH > σv > σh type mainly occurs in the shallow and deep coal seams (<600 m and > 825 m); From 600 to 725 m, a stress transition zone can be observed (σH ≈ σv > σh); The σv > σH > σh type is dominant within depth from 725 to 825 m. With the increase of depth, well testing permeability (k) exhibits a trend of decrease (h < 600 m, 0.055 < k < 0.91mD) - increase (600 < h < 825 m, 0.02 < k < 1.13 mD) - decrease (h > 825 m, k < 0.1 mD), the essence of which is the open and closure of pores and fractures under the control of stress regime and vertical belting. Meanwhile, the correlation between gas content and depth was also illustrated, which shows two trends at the depth of 200–825 m (increase) and 825–1400 m (decrease), respectively. Generally, the coal reservoir deeper than 825 m is characterized by high in situ stress, low permeability and low gas resource, meaning that the geological conditions for CBM development deteriorate. The gas/water production of 500 CBM wells also indicates that the gas recovery rate in deeper coal seams is poorer than that in shallower coal seams. Therefore, a series of corresponding methods for these deep CBM (>825 m) should be taken in the future CBM development strategy
Tectonic fractures are important reservoir spaces for storage of hydrocarbons in low permeability sandstone reservoirs and can significantly improve the permeability; therefore, understanding and predicting their location and intensity in reservoirs are of extreme importance for both the exploration and exploitation planning activities. In the present study, the Early Himalayan Dongying period paleotectonic stress field, the period of time when the majority of tectonic fractures generated in the Dongying Depression, Bohai Bay Basin, China, was simulated and investigated with a three dimensional finite element (3D FE) model. Estimation of the Comprehensive Rupture Rate (CRR) and the relationship between the measured tectonic fracture densities and CRRs were undertaken to quantitatively predict the development and distribution of tectonic fractures in the Es3m low permeability sandstone reservoir. The results indicated that well developed tectonic fractures were located in regions within and between fault zones, near fault tips, and the eastern parts of Block Shishen 100 and adjacent regions. Fault activities were critical to the development and distribution of tectonic fractures in the Es3m reservoir of Block Shishen 100 and adjacent regions. In addition, abnormal high fluid pressures in the Es3m reservoir can promote the development of tectonic fractures.
This paper, demonstrated a scientific approach to prepare a geomechanical model for Bangestan reservoir in an oil well in the south-west of Iran. Bangestan is one of the most important oil reservoirs in the Middle-East that its geomechanical characters are not perfectly known. Moreover, unexpected problems such as casing collapse, production drop and land subsidence occurred in this reservoir that made it necessary to conduct a comprehensive geomechanical model. According to borehole failure observations from a formation micro scanner (FMS) image log, the direction of minimum and maximum horizontal in-situ stresses (Sh and SH) were N35E and N55W, respectively. Also, using poro-elastic formulations, in-situ stress regime was found to be strike-slip (i.e. SH > Sv > Sh). Besides, the optimum mud weight for safe drilling at borehole breakout based on Mohr-Coulomb and Mogi-Coulomb criteria were found 85.12 and 80.42 pcf, respectively, while 79 pcf had been applied in practice. Finally, the precision of the geomechanical model was evaluated using natural fracture observations in the FMS image logs. The FMS logs revealed a total of 510 natural fractures in five clusters. In case of all fracture intervals, petrophysical properties and in-situ stresses decreased and therefore, the model was adequately sensitive to the fractures.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 167915, “Seismic-Frequency- vs. Seismic-Interval-Velocity-Based Pore- Pressure-Prediction Methodologies for a Near-Salt Field in Mississippi Canyon, Gulf of Mexico: Accuracy Analysis and Implications,” by T. Mannon, Stone Energy and University of Louisiana at Lafayette; S. Salehi, University of Louisiana at Lafayette; and R. Young, eSeis, prepared for the 2014 SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 4–6 March. The paper has not been peer reviewed.
The process of risk and uncertainty reduction in unconventional-drilling operations starts with improving techniques for pore-pressure modeling. A study conducted in a near-salt field in deepwater Gulf of Mexico (GOM) that compared the accuracy of seismic-frequency- and seismic-interval-velocity-based methodologies showed significantly higher accuracy for the seismic-frequency- based approach in wells that were in near- or subsalt environments and higher overall accuracy for all wells.
Introduction
The current standard practice for modern pore-pressure prediction relies on interval velocities obtained through seismic surveys. The methodology has seen many changes, but transforms used for interval-velocity-based pore-pressure prediction are for the most part still heavily reliant on the assumption that the porosity trend is directly related to pore pressure. Also, rock velocities are highly dependent on factors such as lithology and porosity, which may have nothing to do with effective stress, the key factor that all pore- pressure models are designed to predict. A seismic application for formation-pressure prediction has been explored that avoids any and all assumed relationships between porosity and effective stress: seismic-frequency-based pore-pressure prediction.
Seismic-Frequency-Based Pore-Pressure Prediction
To grasp the idea of pore-pressure prediction through seismic frequencies, the concept of attenuation and quality factor (Q) must be understood first. Attenuation can be defined in regard to seismic applications as the progressive loss of energy of an acoustic wave traveling through a medium. Attenuation will cause a drop in average frequency for a given seismic signal. Q defines the “quality” of the rock, or any medium through which an acoustic wave is passed. A signal that shows a higher average frequency will be associated with a higher Q value than a signal of lower frequency; thus, attenuation is inversely related to Q.
Natural and drilling-induced fractures that can be identified on borehole walls are classified in terms of the failure initiation mechanisms that generate them and the principal stress orientations with respect to well trajectory. Fracture initiation mechanisms include tensile failure in vertical holes, tensile failure in inclined holes, tensile failure in elliptical boreholes, tensile failure resulting from plastic deformation, shear failure in vertical boreholes subject to low fluid pressures, shear failure in vertical boreholes subject to high fluid pressures, shear failure in inclined boreholes subject to low fluid pressures, shear failure in inclined boreholes subject to high fluid pressures, and failure in boreholes subject to horizontal stresses of equal magnitudes. Analyzing these situations assuming linear elasticity shows that the geometry of fracture traces on borehole walls depends on the in-situ stress tensor, the relative orientations of the stress tensor and the borehole, the fluid pressures in the borehole and in the surrounding rock, the rock's cohesive strength, and its friction angle for shear. Furthermore, hydraulically induced tensile fractures are governed by the least principal stress, but shear fractures are governed by the intermediate and the least principal stresses, contrary to previous conclusions. A classification based on the fracture initiation analysis is presented and is illustrated by examples of different types of borehole wall fractures recorded by image logging tools run in wells in western Canada.
The velocity modeling in the depth domain is a key and difficult point in seismic data processing. In recent years, with the rapid development of pre-stack depth migration technology, the velocity modeling in the depth domain is becoming more and more important. Especially, the reverse-time migration method is developing very fast, but also hard to embody its advantages if there is no high accuracy of depth domain speed. So the accurate velocity model building is now a focused topic of active research. At present, in the industrial production, the tomographic technique is a most common method that is used in the depth domain velocity modeling. Firstly, it establishes an initial velocity model by using the speed coherent inversion method. Then it modifies the initial velocity model by using the error of the common reflection point gathers. This approach often requires taking the manual interaction, and the calculation precision is good. However, the conventional common reflection point in the offset domain has a maximum defect, namely there are many false appearances because of the multiple paths. Focusing on the tomographic technique in the depth domain velocity modeling, this paper establishes a relation with the residual velocity as the independent variable and the residual depth as the objective function. And a Gradient formula about the objedctive function is suggested by using the angle domain common image gathers to replace the conventional common reflection point gathers. We use this formula to make the quantitative analysis and model test for the relationship between the residual velocity and the residual depth. The theoretical analysis and model test demonstrate that the errors of initial velocity model have directional sensitivity. Based on the conclusions, the velocity model building can either increase the computational efficiency of migration velocity modeling, or improve the accuracy. The conventional velocity modeling process can be improved by the new cognition. Firstly, we make the initial velocity greater than the real speed. This process needs to take some manual intervention, namely this step is realized through manually jugging whether the gather is upward or downward. On this basis, we utilize the angle domain common image gathers to replace the offset domain common reflection point gathers, and then the initial velocity model can be updated by using the new formula. Tests on model data and real data indicate that the new method has great practical values.
The Jurassic to Cretaceous sedimentary rocks of the Surat Basin in southeast Queensland host a significant volume of coal seam gas resources. Consequently, knowledge of the in situ stress is important for coal permeability enhancement and wellbore stability. Using wireline log data and direct stress measurements, we have calculated stress orientations from 36 wells, and stress magnitudes from 7 wells across the Surat Basin. Our results reveal a relationship between high tectonic stress and proximity to structures within the underlying “basement” rocks. The influence of tectonic stresses is diminished with depth in areas with thicker sedimentary cover that are relatively far from the basement structures. We suggest that this relationship is due to the redistribution of in situ stresses around areas where basement is shallower, and where basement structures, such as the Leichhardt-Burunga Fault System, are present. This behaviour is explained by a lower rigidity in the thickest basin cover, which reduces the ability to maintain higher tectonic stress. Over the entire Surat Basin, a significant amount of variability in in situ stress orientation is observed. The authors attribute this stress variability to complex plate boundary interactions on the northern and eastern margins of the Indo-Australian plate.
This study is based on the sedimentation conditions, organic geochemistry, storage spaces, physical properties, lithology and gas content of the shale gas reservoirs in Longmaxi Formation of the Jiaoshiba area and the gas accumulation mode is summarized and then compared with that in northern America. The shale gas reservoirs in the Longmaxi Formation in Jiaoshiba have good geological conditions, great thickness of quality shales, high organic content, high gas content, good physical properties, suitable depth, good preservation conditions and good reservoir types. The quality shales at the bottom of the deep shelf are the main target interval for shale gas exploration and development. Shale gas in the Longmaxi Formation has undergone three main reservoiring stages: the early stage of hydrocarbon generation and compaction when shale gas reservoirs were first formed; the middle stage of deep burial and large-scale hydrocarbon generation, which caused the enrichment of reservoirs with shale gas; the late stage of uplift, erosion and fracture development when shale gas reservoirs were finally formed.
The Silurian Longmaxi shale gas play in Jiaoshiba Structure in the southeast margin of the Sichuan Basin is studied to discuss the key controlling factors of shale gas enrichment in complex tectonic zone with high evolution. Jiaoshiba Structure is a faulted anticline which experienced multiphase tectonic movements. The Longmaxi Formation has high thermal evolution degree with Ro more than 2.2%, 35-45 meters thick high-quality shale (TOC > 2%) in its lower part. The reservoir is overpressure with a pressure coefficient of 1.55, and the shale gas production and pressure are stable. Structure type, evolution and geochemical analyses show that there are several stages of hydrocarbon generation, migration and accumulation in the Longmaxi Formation. The joint action of two groups (two stages) of fault systems and the detachment surface at the bottom of the Longmaxi Formation control the development of reticular cracks and overpressure preservation, and it is the key to the shale gas accumulation and high yield. The sealed box-like system in the Longmaxi Formation ensures the gas reservoir dynamic balance. The model of high yield and enrichment of Jiaoshiba shale gas play is “ladder migration, anticline accumulation, fault–slip plane controlling fractures, and box shape reservoiring”. Like in conventional gas plays, good preservation and tectonic conditions are also required to form high yield shale plays in areas which have complex structures, multi-stage tectonic movements, and have high evolution shale.
Fractures play a vital role in the exploration and development of shale oil and gas by providing effective space for shale reservoirs and significantly improving the fluid flow capability. Core observations, microscopic analyses of thin sections, scanning electron microscopy, and Formation MicroScanner Imaging (FMI) were used to determine the types, causes of formation, and development characteristics of the fractures in lacustrine shale reservoirs in the lower part of the Paleogene Shahejie Formation (Es3) in the Zhanhua Depression, Bohai Bay Basin, eastern China. X-ray diffraction (XRD) analysis, total organic carbon (TOC) measurements, and porosity and permeability measurements were used to study the controlling factors of the fractures in the shale reservoirs, and to analyze the impact of the fractures on the shale reservoirs properties and subsequent exploration and development. The studied shale reservoir mainly displays tectonic fractures as well as various types of non-tectonic fractures. The non-tectonic fractures mainly include over-pressure fractures, diagenetic fractures, inter-layer bedding fractures, and fractures of mixed origins. In the study area, the tectonic fractures which were formed under the combined action of tensile and shear stress display the following characteristics. The dip angle of the tectonic fractures varies significantly. Unfilled or half-filled effective fractures have a high proportion. These fractures are mainly oriented in the NE–SW, NNE–SSW, and WNW–ESE directions, with fractures in the NE–SW direction accounting for the highest proportion. The tectonic and non-tectonic fracture development is affected by multiple types of factors such as the presence of faults, mineral composition, lithology, abnormal pressure and organic matter content. Abnormally high pore pressure is a very important factor in the development of non-tectonic fracture. It is inferred that the over-pressure is mainly related to hydrocarbon generation during thermal evolution. Fractures effectively improve the porosity and permeability of the shale reservoirs, and the enhancement of permeability is particularly significant. The current stress field affects the fluid flow capability of the fracture reservoirs, and the present maximum principal stress in Zhanhua Depression is oriented in the NEE–SWW direction, which has a small angle with fractures in NE–SW direction. We propose that the fractures in this direction have the greatest connectivity and thus are a high-priority target for petroleum exploration and development.
This paper presents an evaluation of two fundamentally different stress models: an elastic model, which is based on linear transverse isotropic elasticity, and a failure model, which is based on the concept that rocks are in an equilibrium state of shear failure. The models arc evaluated by using physical parameters measured on core, pore pressure, and in-situ stress data from the Gas Research Institute (GRI) Staged Field Experiments (SFE's) in east Texas. It is shown that the elastic and failure models provide satisfactory predictions for most of the lithologies encountered. However, the failure model is more accurate for predicting stress in soft shales. An example of stress predictions based on log-derived elasticity parameters that gives stress estimations comparable to core-based predictions is also shown.
Think of the money that could be put to better use if we could predict the depth below which commercial production will not be found. It has been suggested that the magic level in geopressured areas is where log resistivity ratios exceed 3.50. The theory offered here, with the hope that it will be carried further, is that the limiting ratio is a function also of overburden stress gradient.
Introduction
In 1965, Hottman and Johnson presented a method for predicting geopressure magnitudes by using resistivity predicting geopressure magnitudes by using resistivity and sonic log data. This technique has received wide acceptance even though the prediction charts were based only on data concerning Tertiary Age sediments in the Gulf Coast area. It was specifically pointed out that these techniques were applicable only in areas where the generation of geopressures is primarily the result of compaction in response to the stress of overburden. Compaction caused by overburden stress was described classically in a soil mechanics book by Terzaghi and Peck in 1948. With a vessel containing a spring and a fluid, they simulated the compaction of clay that contained water. Overburden stress was simulated by a piston, as in Fig. 1. It was shown that the overburden stress, S, was supported by the stress in the spring, , and the fluid pressure, p. Thus, the long-accepted equation of equilibrium was p. Thus, the long-accepted equation of equilibrium was established.
S = + p...................................(1)
If Fig. 1 and Eq. 1 are studied, it is obvious that if S is increased and the fluid is allowed to escape, or must increase while p remains as hydrostatic pressure. However, if the fluid cannot escape, p must also increase as S is increased. Hubbert and Rubey published a comprehensive treatment of this theory as related to sedimentary rock compaction. They showed that as the overburden stress is increased as a result of burial, the porosity of a given rock is decreased. Therefore, some fluid that was once in the pores of a given formation was later squeezed out by compaction. In many such cases, there is no escape route for the fluid, and thus the fluid becomes overpressured according to Eq. 1. This happens in many areas, and such generated overpressured zones are often called "abnormal" pressure zones or "geopressure" zones. Hottman and Johnson recognized the main significance of the preceding theory and developed a very useful relationship between electrical log properties and geopressures. They reasoned that since rocks are more resistive to electrical current than is formation water, a well compacted shale containing less water (because the water has escaped) is more resistive than a less compacted shale containing more water (one in which the water has not escaped to the same degree). Also, they reasoned that a sequence of normally compacted sediments (in which water is free to escape) should have a normally increasing resistivity trend. They substantiated this when they plotted resistivities from actual well logs. Any resistivity decrease from the well established normal trend indicates the, presence of abnormally high-pressured zones. Empirical data from well tests and logs were used to develop a correlation of the pore pressure gradient as a function of the resistivity departure ratio (see Fig. 2).
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INTRODUCTION
Many Tertiary basins in the world have undergone rapid sedimentation of clastic rocks, including floods of volcanic ash with montmorillonite. Lenticular-shale or sand bodies that are capped by impervious montmorillonite or carbonate layers are unable to expel the connate water, oil, and gases entrapped within and, as a result, become undercompacted and overpressured when deeply buried by continued deposition of sediments. Pressures within these lenticular, entrapped sedimentary zones can range as high as 95% of the overburden load and frequently exceed 70%. Prediction of these overpressured zones from surface sources prior to drilling a well through them can aid in preventing dangerous and expensive blowouts. Prediction can aid in designing casing and drilling fluid programs to permit safe penetration of these zones and continue drilling to reservoir rocks at greater depths.
INTERPRETATION OF VELOCITY ANALYSES
In the course of a seismic reflection survey, a general practice is to use common depth point (CDP) profiling. The many closely spaced source and receiver positions produce a large number of ray paths to common reflection points that permit the calculation of root-mean-square velocities for each reflection event and time. Fig. 1 illustrates a typical CDP velocity analysis with points representing all of the time/velocity pairs determined by applying normal moveout corrections and summing the trace amplitudes. The range of velocities used in the analysis includes those associated with primaries, multiples, and other coherent events. The amplitude of these types of events is not a discriminating parameter in the interpretation of velocity analyses. It is not uncommon for multiples to be several times stronger than primary events at the same reflection time. Therefore, it is essential that all coherent events be represented by a time/velocity pair. On this display, even those pairs represented by a mere dot are necessary to a proper interpretation. The columns at the right are graphs of the polarity with amplitude and dips of the events in milliseconds per CDP spread and direction of dip. The listing shows the selected RMS velocity file, two-way time, dip and direction, and amplitude and polarity for the highest amplitude events per 100-millisec gate. It is preferable to use the complete set of values unlimited by amplitude discrimination.
COMPARISON OF SEISMIC RECORD SEDTION, WELL DATA, AND SEISMIC VELOCITY INTERPRETATION
A portion of a seismic record section is shown in Fig. 2 illustrating the location of the wellbore, the sonic log of the well on the left, and a pseudosonic log derived from an interpretation of the CDP velocity analysis near the well location on the right. One can correlate the reflection events to velocity contrasts on both sonic logs. Of particular interest is the high contrast at 2.55 seconds, which was predicted as a significant overpressured zone at 11,005 ft from the seismic data and was encountered in the well at a slightly greater depth of 11,042 ft. The predicted formation pressure was 8321 psi requiring 14.5 lb/gal drilling fluid.
The horizontal compressive stress orientations for Mandapeta field in Krishna-Godavari (K-G) basin had been calculated from borehole breakout data using four-arm dipmeter caliper logs. The minimum horizontal stress magnitude for Mandapeta field was calculated from pore pressure data using poroelastic equation. Three-dimensional (3-D) stress modeling using finite element analyses has been carried out for layered sediments and faulted layered sediments in the Mandapeta sub-basin. The length and width of the models are chosen as 5 km and 2 km respectively. Vertical depths of models are considered for sediments at depth 2 km to 5 km. This paper presents a numerical study of stress distributions (contours and trajectories) around fault models of layered geometries, submitted to overburden and unequal horizontal compressive loads. Reorientation and magnitude variation of in-situ stresses near faults and stress discontinuities across faults are observed. Changes in the stress patterns are observed at the interfaces between sediments due to faulting and sediment-basement layers due to contrast in elastic constants. Remarkable stress gradients are observed between the sediment and basement. Magnitudes of normal component of stress decrease near the faulting whereas shear stress magnitudes increase at the faulting site. There is increase of horizontal principal stresses in the downthrown faulted layers. The maximum horizontal principal stress rotates about 90° just adjacent to the fault. Fluid flow at depth of oil reservoir could be indirectly influenced by the stress contours and by geometries of the stress trajectories. Fluid migration in low permeability reservoir may occur in response to mean stress gradients induced by the tectonic loading. The areas of high mean stress gradient are located at the interface between sediment and basement whereas the areas of low mean stress gradient is exactly coinciding with the areas of upper sediments.
Well log analysis has been carried out to evaluate resistivity and density log data of about seven wells distributed over 3.5 sq. km area of Rangamati, Raniganj coalfield, India. Geological logs of these boreholes have recorded occurrence of four major consistent coal seams (A, B, C and D) at different depths, varying between 52 to 200 m in the area. Cleat volume/porosity ranges from 1% to about 3% in this area. Vertical stress magnitude ranges from 0.55 to 4.59 MPa from 52 to 202 m and increases with depth. The gradient of vertical stress magnitude decreases within coal seams compared to the stress gradient at roof and floor of the same seams. A methodology is proposed for estimation of permeability for a macro-cleat system of coal from well log derived porosity and from known cleat spacing from Rangamati area. Permeability value ranges from 0.5 md at a depth of 193–200 m to 18 md at a shallower depth of 45–53 m while vertical stress decreases from 4.566 MPa to 1.254 MPa respectively. Permeability values of four coal seams have been correlated with effective horizontal stress to infer the maximum horizontal stress orientation.
a new high density dataset reveals local stress rotations
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