Shale Compaction Research Articles

Shale anisotropic rock-physics model incorporating the effect of compaction and nonplate mixtures on clay preferred orientation

Compared with other sedimentary rocks, the strong elastic anisotropy of shale is extremely prominent, which is mainly caused by the preferred orientation and platy nature of its clay minerals. Especially in seismic reservoir characterization, a suitable and correct estimation of the shale elastic anisotropy can improve the accuracy of the shale seismic inversion and prediction. Due to the long-term compaction of shale and the rearrangement of minerals, its microstructure and macrostructure are more complex, resulting in obvious anisotropic characteristics of shale. Existing methods do not incorporate the impact of nonplate particles on clay platelets, or indirectly incorporate it through empirical formulas, resulting in poor applicability and errors in the rock-physics models. To reveal the main causes of the anisotropy of clay minerals, a theoretical model incorporating the effect of compaction and nonplate particles on the preferred orientation of clay platelets is developed using experimental data and electronic scanning results. Based on theoretical analysis, an orientation distribution function (ODF) based on the effect of compaction and nonplate particles is derived, which not only incorporates the influence of compaction but also further incorporates the effect of other nonplate particles, such as quartz, which makes the established shale anisotropic rock-physics model more reasonable and accurate. Then, an improved anisotropic shale rock-physics model is developed using the compaction and nonplate particles-based ODF. The prediction results indicate that the presence of nonplate particles has an inhibitory effect on the preferred orientation of clay platelets, which is verified by the measured experimental data and indicates that our method is reliable and effective.

Drilling data-calibrated shale compaction models for pore pressure evaluation from geophysical well logs in the North Alpine Foreland Basin, SE Germany

This paper combines quality-controlled pore pressure measurements and indicators with geophysical well logs from 310 deep wells to evaluate the pore pressure distribution in the overpressured North Alpine Foreland Basin in SE Germany. Previous studies relied chiefly on low-resolution check shots and vertical seismic profiles calibrated to only a few pore pressure measurements. The current study, based on sonic and electrical resistivity logs, indicates that more than one shale normal compaction trend is required to appropriately assess pore pressure from geophysical well logs. Thereby, the necessary adjustments of the derived compaction trends apply to both sonic and resistivity data, which possibly reflect a gradual change in the mineralogical composition with decreasing clay content or progressing cementation from north to south or an increase in horizontal loading-driven compaction towards the North Alpine Thrust Front. The newly derived compaction-based pore pressure distribution is combined with drilling data-based pore pressure evaluations and offers a comprehensive update of previous pore pressure investigations in the North Alpine Foreland Basin. Our study is therefore of key importance for optimized well planning and cost-effective drilling in the course of the recent expansion of deep geothermal energy exploration in the overpressured North Alpine Foreland Basin.

Mechanical Behavior of Weathered Compacted Shales

Mechanical Behavior of Weathered Compacted Shales

Geobotanical and Biogeochemical Prospecting Method of Complex Sulphide Ore of Pb-Zn-Cu-Ba in Abuni-Adudu areas of the Middle Benue Trough, Nigeria

This research work focused on two plant species namely, the Anogeissus leiocarpus (DC.) and Dichrostachys cinerea for mineral prospecting. The two plants were sampled based on their occurrence, abundance and outlook. Twelve samples (six each of Anogeissus leiocarpus (DC.) and Dichrostachys cinerea) were collected around Abuni-Adudu mining communities in the Middle Benue Trough, Nigeria. In addition, bulk ore and twelve soil samples were also collected and analysed for correlation. Geologically, the study area is made up compacted shale, baked shale (hornfels), and sandstones of sedimentary origin, which are intruded by tertiary basalts of igneous origin. Samples were analysed for elemental composition, using inductively coupled plasma mass spectrometry method. Analysis revealed that the geobotanical method of prospecting for Pb-Zn-Cu-Ba mineralization in the area is promising as biogeochemical data indicated that the Dichrostachys cinerea are good indicator of Pb-Zn-Cu mineralization while the Anogeissus leiocarpus were indicative of Barium. Given the relatively low concentration of Barium in the ore (3.8 ppm) as against concentration in the soil samples, which ranges from 83 ppm (sample YS6) to 552 ppm (sample YS12), Barium has its source from the shale and sandstone or nearby Barite mineralization and not the ore.

Experimental and constitutive modeling of the anisotropic mechanical properties of shale subjected to thermal treatment

The physical and mechanical properties of shale exhibit significant anisotropy, impacting the design and construction of high geothermal tunnels and deep resource mining. Laboratory studies on the physical and anisotropic mechanical properties of shale after various thermal treatments showed that rising temperatures caused an exponential decline in shale’s bulk and density, and the uneven expansion of the mineral particles within the rock caused a decrease in its uniaxial compression strength (UCS) and elastic modulus while increasing their anisotropy. The UCS is U-shaped with a change in bedding dip angle, whereas the elastic modulus is U-shaped or shoulder-shaped. Under the assumption that the rock microelement obeyed the Weibull distribution, the microstructure tensor improved Hoek–Brown strength criterion was introduced as the damage basis. Then a thermal–mechanical coupling damage constitutive model considering bedding dip angle and temperature was established. The model was found to be valid via the test results, especially in capturing the compaction and yield softening stages of shale. These findings have reference value for both underground structural engineering and deep resource mining.

Evaluation of formation susceptibility and sand production potential in an offshore field, Niger Delta Basin, Nigeria

Wellbore instability and sand production are all common challenges in the Niger Delta oil province, resulting in high drilling and production cost as well as damage to oil facilities. The vulnerability of lithologic formations to wellbore instability and resultant sand production is investigated in the four delineated reservoirs of the “Areo” field, western part of Niger Delta Basin. The foundation for establishing the geomechanical properties in this study was a 1-dimensional mechanical earth model, using gamma ray (GR), density (RHOB), compressional slowness (DTC), and shear slowness (DTS) logs. Within the Areo oil field, two wells (well 001 and well 002) were correlated. The evaluated formations are still primarily composed of compacted shale and unconsolidated sandstone, with reservoir sand units exhibiting lower elastic and rock strength properties than shale units. High compressibility and porosity make sand more brittle, while low compressibility and porosity make shale stiffer due to high moduli. The maximum force that can be applied to a shale unit without causing it to fail is 17.23 MPa, which is the maximum average rock strength of the shale. It means that shale requires more vertical stress or pressure than sand does in order to deform it (15.06 MPa). The three sand prediction approaches used in the analysis of sand production predictions have cut-off values that are higher than the average values of the formations. The Schlumberger sand production index method (S/I) indicates that the reservoir has potential for sand influx in the two wells, with the average of the four reservoirs studied in wells 001 and 002 being 1.55 × 1012 psi and 1.14 × 1012 psi respectively. However, when a formation's sand production index is less than 1.24 × 1012 psi, as it is in this study, the formation is likely to produce sand. These findings support the notion that the defined sandstone units are highly unconsolidated and have a high potential for producing sands; therefore, sand control techniques must be factored into process optimization and cost reduction plans.

Tectonic fluid expulsion: U-Pb evidence for punctuated hydrothermal fluid flow and hydraulic fracturing during orogenesis

Tectonic fluid expulsion has been linked to fluid flow in permeable foreland basin sequences, but it is unclear how fluids migrate through underlying low-permeability successions. Here we report U-Pb data which indicate that fluids expelled during tectonic compression migrated through older compacted shales inboard of the deforming craton margin by fracture permeability and enhanced diffusion. From a ∼350 m drill-core interval of Neoarchean shale (drill-hole ABDP9), Hamersley region, Australia, we document abundant bedding-parallel veins indicating pervasive hydraulic fracturing. Thermometry of vein-filling chlorite indicates temperatures between 329-374°C, which is higher than estimates (175-280°C) from metamorphic assemblages in underlying basalts, implying the passage of hydrothermal fluids. New in situ secondary ion mass spectrometry (SIMS) U-Pb geochronology of monazite and xenotime in bedding-parallel veins verifies and expands earlier results, showing that microfracturing and hydrothermal fluid flow spanned ∼650 million years and was restricted to five short intervals: 2.30 Ga, 2.20 Ga, 2.10 Ga, 2.05 Ga and 1.65 Ga. Three of the five age populations coincide with known fabric-forming orogenic events (i.e. 2.30 Ga Sylvania orogeny; 2.22-2.15 Ga Ophthalmia orogeny; 1.68-1.65 Ga Mangaroon orogeny), which are focused along the southern Pilbara Craton margin. Our results show that the timing of veining was not random, but coeval with major orogenic events, linking fluid overpressure and hydraulic fracturing to the expulsion of heated orogenic fluids 100s of km inboard of the craton margin. The crack-seal veins indicate repeated cycles of fluid overpressure resulting in hydrofracturing and fluid drainage, followed by cavity collapse. The tectonic expulsion of pressurized hydrothermal fluids produced fracture and matrix permeability in Earth's upper crust, leading to episodic open-system behaviour with enhanced fluid-rock reactions and the large-scale transfer of heat and mass.

Seismic attributes and static reservoir simulation applications for imaging the thin-bedded stratigraphic systems of the Lower-Cretaceous Lower Goru fluvial resources, Pakistan

• Constructed workflow is a vital case for discovery of gas-bearing fluvial stratigraphic traps. • The SRSN resolves the thin-bedded point bar sandstone deposits in the basin. • AI and thicknesses for point bars sandstone are -0.214 to -0.219 g/c.c.*m/s and 17 to 19 m. • SRSN image sedimentary facies during the sea-level rise and fall events. Fluvial depositional systems accommodate a variety of primary stratigraphic-based trapping pools (STP) such as the channelized sands (CS) and point bars (PB). When they are encased within the non-porous and compacted shales, they develop hydrocarbon-bearing reserves. However, these STP are developed during the rapidly rising sea level and very slow fall, which creates hurdles in the development of accommodation space to accumulate the thin-bedded (hydrocarbon-bearing) and coarse-grained PB. PB are the primary stratigraphic traps within the fluvial hierarchy. Therefore, they require sophisticated tools such as reflection-based impedance reservoir simulations to simulate the thickness, accommodation space, proximal and distal locations, and sealing configurations of PB from a 3D perspective. The conventional seismic amplitudes are not sufficient enough to quantitatively portray these seismic sedimentological attributes due to a lack of preserved amplitudes and tuning frequency content aimed at fluvial-dominated clastic sequences. Therefore, the ultimate goal of conducting this research work is to detect thin-beds of PB and CF aimed at accumulating and generating hydrocarbon-posture STP. These thin-bedded reservoir facies are very delicate in tuning the frequency of the sub-surface systems. They require amplitude-based seismic data interpretation tools such as amplitude-based seismic attributes and inverted reservoir simulations. These tools can image the exact thickness of the reservoir lithology and types of fluids compared to the bandlimited geometrical attributes. Generally, the inverted reservoir simulations reconstruct the reflection-based impedances for the stratigraphic reservoirs, which helps in the quantification of the sub-surface thin-bedded stratigraphic systems. Therefore, the amplitude-based seismic attributes and thin-bedded wedge static reservoir simulation (SRSN) tools in Pakistan's Indus Basin. The amalgamated root-mean-square (RMS)-based seismic amplitude and frequency highlighted a full of twist continuous meander channel with a sinuosity index (S.I) > 2.7. Strong low-frequency shadows are observed at 23 Hz magnitudes that authorize the restoration of petroleum-posture fluvial-dominated PB STP. The amplitude attenuation model using the continuous wavelet transform (CWT) showed attenuation of spectral energy below the PB. The SRSN determined a 16 m thickness of STP using a constant velocity of 3449 m/s, which pinched out in the east of the Indus Basin. The predicted physical attributes from SRSN and their cross-plots against the thickness constraint have discriminated against the dominant sedimentary facies of the fluvial system during the significant rising and negligible falling sea levels. The predicted physical parameters have enabled vigorous controls aimed at developing accommodating intervals that have stored a significant amount of hydrocarbon-bearing PB. The quantitative characterization has enhanced acoustic impedance [AI] [g/c.c.*m/s] and thickness of PB with a strong correlation coefficient of R 2 >0.93. The predicted AI [g/c.c.*m/s] and thicknesses [m] aimed at PB were -0.214 to -0.219 g/c.c.*m/s and 16 to 19 m, respectively. Therefore, the SRSN can be used as a dynamic instrument for the accurate prediction of AI [g/c.c.*m/s] and thickness for the characterization of fluvial systems. This workflow may serve as a vital example for exploring the oil and gas-bearing stratigraphic system within the Indus Basin and similar basin settings.

New Models for Predicting Pore Pressure and Fracture Pressure while Drilling in Mixed Lithologies Using Artificial Neural Networks.

Precise prediction of pore pressure and fracture pressure is a crucial aspect of petroleum engineering. The awareness of both fracture pressure and pore pressure is essential to control the well. It helps in the elimination of the problems related to drilling, waterflooding project, and hydraulic fracturing job such as fluid loss, kick, differential sticking, and blowout. Avoiding these problems enhances the performance and reduces the cost of operation. Several researchers proposed many models for predicting pore and fracture pressures using well log information, rock strength properties, or drilling data. However, some of these models are limited to one type of lithology such as clean and compacted shale formation, applicable only for the pressure generated by under compaction, and some of them cannot be used in unloading formations. Recently, artificial intelligence techniques showed a great performance in petroleum engineering applications. Hence, in this paper, two artificial neural network models are developed to estimate both pore pressure and fracture pressure through the use of 2820 data sets obtained from drilling data in mixed lithologies of sandstone, carbonate, and shale. The proposed artificial neural network (ANN) models achieved accurate estimation of pore and fracture pressures, where the coefficients of determination (R2) for pore and fracture pressures are 0.974 and 0.998, respectively. Another data set from the Middle East was used to validate the developed models. The models estimated the pore and fracture pressures with high R2 values of 0.90 and 0.99, respectively. This work demonstrates the validity and reliability of the developed models to calculate pore and fracture pressures from real-time surface drilling parameters by considering the formation type to overcome the limitation of previous models.

Research on Pore Pressure Detection While Drilling Based on Mechanical Specific Energy

The detection of the formation of pore pressure while drilling is of great importance to ensure safe drilling operations. At present, the dc-exponent concept is mainly used to detect pore pressure while drilling. The dc-exponent concept is based on the theory of shale compaction, which is limited when used in carbonate rocks. A mechanical specific energy (MSE)-based method is proposed to detect pore pressure in deep, complex intervals. The method is based on the theory that the energy consumed by the bit to break and remove a unit volume of rock can reflect the effective stress and pore pressure of the rock in situ. In this paper, a torque and weight on bit (WOB) transfer model is proposed for estimating the downhole torque and WOB using drill string mechanics. Meanwhile, the rotary speed and torque of the positive displacement motors under compound drilling are considered, and the model of total MSE under compound drilling is modified. The MSE-based method was used to estimate the pore pressure in a region in western Sichuan, and there is a good agreement between the detected and measured pore pressure. The results demonstrate that the accurate computed MSE-based method is useful in detecting pore pressure in deep complex intervals.

Specific features of shale compaction in the Azerbaijan sector of the South Caspian Basin

Specific features of shale compaction in the Azerbaijan sector of the South Caspian Basin

A 3D empirical model of standard compaction curve for Thailand shales: Porosity in function of burial depth and geological time

Abstract Shale rock formed from small clay particles, and shale compaction is an essential factor to estimate shale reserves. The classical Athy’s model has been used to obtain the shale compaction curve to describe the relationship between porosity and depth, an essential input data for basin modelling. But recent studies revealed that burial time, among other factors, should be considered and that geological age is another important factor in some regions. This is because geological and lithological histories are crucially different among geological ages. This study employed the newest data of Thailand shales and confirmed that different geological ages (Cenozoic, Mesozoic, and Paleozoic ages) require different shale compaction curves by estimating numerical geological time with the relationship of velocity and depth in each geological age. We obtained empirical models of the shale compaction curve of each geological age by multi-linear regression. The standard curve of shale compaction with the relationship among porosity, depth, and time, proposed in a previous study, was also re-affirmed with the newly obtained models.

Impacts of Addition of Palm Kernel Shells Content on Mechanical Properties of Compacted Shale Used as an Alternative Landfill Liners

The design of landfill liners of waste disposal to reduce migration of leachate containment, low swelling, and shrinkage and ensure sufficient shear strength to resist bearing capacity and instability of the landfill has been a major challenging task to landfill engineers. Over the last decade, there has been an increase in research on the stability of substitute materials as liners that are environmentally friendly, cost-effective, and socially beneficial due to the growing cost of traditional landfill liners. In this regard, geotechnical tests were conducted on shale samples treated with 0–12% (increment of 2%) of palm kernel shell ash (PKSA) and pulverized palm kernel shell (PPKS) to evaluate their suitability as alternative landfill liners using West African Standard (WAS) and Modified AASHTO Standard (MAS) for compactive energy. The shale has more percentage of finer fractions, thus classified as poorly graded soil (A-7-5). The Atterberg limit tests show that liquid and plastic limits decrease with an increase in plasticity index as the percentage of addition of PKSA and PPKS content increases. The results also established that the maximum dry density (MDD), volumetric shrinkage strain (VSS), and hydraulic conductivity significantly decrease, while the optimum moisture content (OMC) increases as the content of PKSA and PPKS increases at both compactive efforts. The maximum strengths of 380.30 and 448.70 kPa were obtained at 4% of both stabilizers. From the results, it can therefore be concluded that the treated compacted shale meets the condition of the suitability of landfill liners. Furthermore, with the use of industrial and agricultural wastes such as palm kernel shells as replacement materials with natural soils used as liners, significant social, economic, and environmental impact of landfills and reduction in wastes can be achieved. The research results can provide a reference for similar conditions of landfill liners worldwide.

Evaluation of the Accumulation Conditions and Favorable Areas of Shale Gas in the Upper Palaeozoic Marine-Continental Transitional Facies in the Daning-Jixian Area, Ordos Basin

This study focuses on the organic-rich mud shale in the Upper Palaeozoic transitional facies in the southeastern margin of the Ordos Basin. It systematically analyzes the shale gas accumulation conditions of the organic-rich mud shale in the Lower Permian Shanxi-Taiyuan Formation, including the thickness, distribution, organic matter type and content, thermal maturity, reservoir space, gas-bearing property, and rock brittleness. The results show that the thick dark mud shale contains a high organic matter content, is a suitable kerogen type for gas generation, and exhibits moderate thermal evolution, providing excellent conditions for hydrocarbon accumulation. Residual primary pores formed by shale compaction, secondary pores formed by organic matter hydrocarbon generation, clay mineral transformation and dissolution, and fractures provide suitable reservoir spaces for shale gas. The shale in the study area has a higher gas content than the shale strata in the marine basins of the United States. In addition, the content of brittle minerals such as quartz is higher, and Poisson’s ratio is lower, facilitating the subsequent transformation. The accumulation conditions indicate the high potential of the study area for shale gas exploration and development. The geological analogy method is used to compare the study area with five major shale gas basins in the United States. The results indicate that the shale gas resources of the Shanxi-Taiyuan Formation in the study area are in the range of 2800– 3200 × 10 8 m3. The primary controlling factors affecting shale gas reservoirs in this area are the abundance of organic matter, thermal maturity, shale thickness, and quartz content. Favorable areas are predicted based on these factors.

Lithology Identification, Shale Volume Estimation and Formation Wate Saturation of Fenchuganj Gas Field Using Wireline Log Data

This study has been undertaken with a view to interpreting and analyzing different types of logs, detecting hydrocarbon-bearing sand zone, identifying the lithology, estimating shale volume, and determining water saturation of the formation of the Fenchuganj gas field. Fenchuganj gas field is in the southern part of Bangladesh in the Sylhet division. It lies in the Surma basin and characterized as a water drive gas field. Gamma Ray (GR) log and Spontaneous Potential (SP) log analysis help to interpret the formation lithology. After interpreting lithology, the gamma-ray log and SP log were analyzed further, and the hydrocarbon-bearing zone was detected. From the analysis of different logs, for well 4, so many gas-bearing sand zones have been detected. The gas-bearing zones are found between (1585-1595) m, (1600-1610) m, (2409-2420) m, (2265-2270) m, (2295-2303) m, (2435-2450) m, (2465-2480) m, (3150-3155) m, (2955- 2960) m. These are the gas-bearing zones of fenchugonj well-4 determined from the composite log of this field. Water-bearing sand zones are between (1708-1714) m and the fully compacted shale zone is between (1920-1930) m. From the analysis of different logs, for well 5, so many gas-bearing sand zones have been detected. The gas-bearing zones are found between (2365-2385.5) m, (1820-1830) m, (1782-1803) m, (305-308) m, (336.5-338.5) m, (607.5-609.5) m. These are the gas-bearing zone of fenchugonj well-5 determined from the composite log of the field. Shale volume has been estimated from the gamma-ray log and from resistivity logs by the true resistivity method. In well 4, the calculated value of shale volume by Gamma Ray method and true Resistivity methods were respectively 15% and 6%, in well 5 these values were 7.25% and 7.64%. Formation water resistivity was determined from the formula and taken as 0. 1ohm-m and mud filtrate resistivity 0.76 ohm-m. for well-4 and for well-5 it was taken as 0.7 ohm-m (from the provided composite log of well 4 and 5). Formation true resistivity Rt was estimated directly from the ILD log and true resistivity log. The average value of Rt for well-5 was 33.75 ohm-m and for well-4 the value is 34.09 ohm-m. From the RFOC log, flushed zone resistivity Rxo was calculated directly. Water saturation has been determined by three different techniques named Archie, Indonesia, and Simandoux method. For well 5, the value of average water saturation found from Archie, Indonesia, and Simandoux model was 8.5%,22%, and 24.84%, and for well-4. The value of average water saturation was found as 7.3%,18%, 20.51%respectively.

Proposed Model for Shale Compaction Kinetics

Shales are the most abundant class of sedimentary rocks, distinguished by being very fine-grained, clayey, and compressible. Their physical and chemical properties are important in widely different enterprises such as civil engineering, ceramics, and petroleum exploration. One characteristic, which is studied here, is a systematic reduction of porosity with depth of burial. This is due increases in grain-to-grain stress and temperature. Vertical stress in sediments is given by the overburden less the pore fluid pressure, σ, divided by the fraction of the horizontal area which is the supporting matrix, (1−φ), where φ is the porosity. It is proposed that the fractional reduction of this ratio, Λ, with time is given by the product of φ4m/3, (1−φ)4n/3, and one or more Arrhenius functions Aexp(−E/RT) with m and n close to 1. This proposal is tested for shale sections in six wells from around the world for which porosity-depth data are available. Good agreement is obtained above 30–40 °C and fractional porosities less than 0.5. Single activation energies for each well are obtained in the range 15–33 kJ/mole, close to the approximate pressure solution of quartz, 24 kJ/mol. Values of m and n are in the range 1 to 0.8, indicating nearly fractal water-wet pore-to-matrix interfaces at pressure solution locations. Results are independent of over- or under-pressure of pore water. This model attempts to explain shale compaction quantitatively. For the petoleum industry, given porosity-depth data for uneroded sections and accurate activation energy, E, paleo-geothermal-gradient can be inferred and from that organic maturity, indicating better drilling prospects.

Lithofacies classification using Bayes theorem method : Case study Western Desert, Egypt

This paper shows the availability of using the Bayesian classification method to predict class membership probabilities in one of the deep tight reservoirs in Western Desert, Egypt. The workflow of our project that using the Bayesian method used the deterministic petrophysical results of three training wells to train the data and extract the classifiers. The classified data were modeled using Gaussian distribution for each lithofacies. The used wells were acquired from a deep Jurassic gas reservoir in the Western Desert of Egypt. The fitting between actual and modeled data has been reached by minimizing the L2 norm. Besides, a cross-validation process was used for validating the resulted classifiers. Finally, the Bayesian classification method can predict the GWC with an accuracy of 4 m. To avoid probability interference caused by the compacted shale more data should be added to the initial model.

Mobilization of oil in organic matter and its contribution to oil production during primary production in shale

Oil in shale formation includes free oil in inorganic pores and ad-/absorbed oil within organic matter (OM). The latter is immobile without exerting extra forces due to the strong molecular interactions between oil and OM. In this study, we conducted newly designed two-core series oil flow experiments with shale and sandstone samples to reveal the mechanisms of mobilizing the oil in OM, and a new phenomenon in shale samples was observed. Analysis using the theory of shale compaction showed that the OM and oil within it are compressed by the inorganic matrix in the depletion process, raising the effective stress of OM and its pore pressure. When the effective stress of OM attains a threshold value, the oil in OM is squeezed out into the surrounding inorganic matrix. For the first time, a threshold stress change of OM is defined, and a model is proposed for describing the mechanisms of mobilizing the oil in OM validated by the experimental results. The values of threshold tress change τ increases from 0.14 MPa to 0.48 MPa with the saturation pressure increasing from 0.51 MPa to 1.47 MPa. Field scale modeling shows that the mobilization of oil in OM is greatly affected by the permeability of OM and inorganic matrix, the stiffness of inorganic matrix, pressure drawdown, and the matrix size.

Porosity model and pore evolution of transitional shales: an example from the Southern North China Basin

The evolution of shale reservoirs is mainly related to two functions: mechanical compaction controlled by ground stress and chemical compaction controlled by thermal effect. Thermal simulation experiments were conducted to simulate the chemical compaction of marine-continental transitional shale, and X-ray diffraction (XRD), CO2 adsorption, N2 adsorption and high-pressure mercury injection (MIP) were then used to characterize shale diagenesis and porosity. Moreover, simulations of mechanical compaction adhering to mathematical models were performed, and a shale compaction model was proposed considering clay content and kaolinite proportions. The advantage of this model is that the change in shale compressibility, which is caused by the transformation of clay minerals during thermal evolution, may be considered. The combination of the thermal simulation and compaction model may depict the interactions between chemical and mechanical compaction. Such interactions may then express the pore evolution of shale in actual conditions of formation. Accordingly, the obtained results demonstrated that shales having low kaolinite possess higher porosity at the same burial depth and clay mineral content, proving that other clay minerals such as illite–smectite mixed layers (I/S) and illite are conducive to the development of pores. Shales possessing a high clay mineral content have a higher porosity in shallow layers (< 3500 m) and a lower porosity in deep layers (> 3500 m). Both the amount and location of the increase in porosity differ at different geothermal gradients. High geothermal gradients favor the preservation of high porosity in shale at an appropriate Ro. The pore evolution of the marine-continental transitional shale is divided into five stages. Stage 2 possesses an Ro of 1.0%–1.6% and has high porosity along with a high specific surface area. Stage 3 has an Ro of 1.6%–2.0% and contains a higher porosity with a low specific surface area. Finally, Stage 4 has an Ro of 2.0%–2.9% with a low porosity and high specific surface area.

Life Cycle of Oil and Gas Fields in the Mississippi River Delta: A Review

Oil and gas (O&amp;G) activity has been pervasive in the Mississippi River Delta (MRD). Here we review the life cycle of O&amp;G fields in the MRD focusing on the production history and resulting environmental impacts and show how cumulative impacts affect coastal ecosystems. Individual fields can last 40–60 years and most wells are in the final stages of production. Production increased rapidly reaching a peak around 1970 and then declined. Produced water lagged O&amp;G and was generally higher during declining O&amp;G production, making up about 70% of total liquids. Much of the wetland loss in the delta is associated with O&amp;G activities. These have contributed in three major ways to wetland loss including alteration of surface hydrology, induced subsidence due to fluids removal and fault activation, and toxic stress due to spilled oil and produced water. Changes in surface hydrology are related to canal dredging and spoil placement. As canal density increases, the density of natural channels decreases. Interconnected canal networks often lead to saltwater intrusion. Spoil banks block natural overland flow affecting exchange of water, sediments, chemicals, and organisms. Lower wetland productivity and reduced sediment input leads to enhanced surficial subsidence. Spoil banks are not permanent but subside and compact over time and many spoil banks no longer have subaerial expression. Fluid withdrawal from O&amp;G formations leads to induced subsidence and fault activation. Formation pore pressure decreases, which lowers the lateral confining stress acting in the formation due to poroelastic coupling between pore pressure and stress. This promotes normal faulting in an extensional geological environment like the MRD, which causes surface subsidence in the vicinity of the faults. Induced reservoir compaction results in a reduction of reservoir thickness. Induced subsidence occurs in two phases especially when production rate is high. The first phase is compaction of the reservoir itself while the second phase is caused by a slow drainage of pore pressure in bounding shales that induces time-delayed subsidence associated with shale compaction. This second phase can continue for decades, even after most O&amp;G has been produced, resulting in subsidence over much of an oil field that can be greater than surface subsidence due to altered hydrology. Produced water is water brought to the surface during O&amp;G extraction and an estimated 2 million barrels per day were discharged into Louisiana coastal wetlands and waters from nearly 700 sites. This water is a mixture of either liquid or gaseous hydrocarbons, high salinity (up to 300 ppt) water, dissolved and suspended solids such as sand or silt, and injected fluids and additives associated with exploration and production activities and it is toxic to many estuarine organisms including vegetation and fauna. Spilled oil has lethal and sub-lethal effects on a wide range of estuarine organisms. The cumulative effect of alterations in surface hydrology, induced subsidence, and toxins interact such that overall impacts are enhanced. Restoration of coastal wetlands degraded by O&amp;G activities should be informed by these impacts.