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This paper presents the zonal geochemistry and elasticity characteristics of gallium- and lithium-rich No. 6 coalbed in the Haerwusu mine and discusses interpretation methodologies of coal-hosted gallium and lithium resources using lab-measured samples and field-measured wireline logs. The results demonstrate that both coal-composition-based and elastic-parameter-based classifications yield similar results, categorizing the coalbed into subzones related to coal quality. Material compositions, elastic properties, critical metals, and host minerals exhibit zonal distribution characteristics within the ultrathick No. 6 coalbed. Three-class classifications significantly enhance correlations among host minerals, elastic parameters, and critical metals, albeit with differing trends among classes. In classes II and III (ultralow- and low-ash-yield coals), boehmite and kaolinite primarily host gallium and lithium, respectively. In class I (medium-ash-yield coal), gallium is associated with kaolinite, while lithium lacks specific mineral associations. Constrained by wireline logs, a rock physics modeling strategy is proposed to link mesoscale coal compositions to macroscale elastic responses. Moreover, explicit correlations between host minerals and critical metals are established, connecting macroscale elastic responses to microscale gallium and lithium enrichments and exploring interpretation methods of coal-hosted critical metals. Preferred lithium interpretation methods include compositional ternary plots and elastic parameter cross plots, while preferred gallium interpretation methods involve boehmite-gallium and elastic parameter-gallium fitting. These findings may contribute to understanding the enrichment mechanisms and interpretation technologies of coal-hosted critical metals in ultrathick low-rank coalbeds. [ABSTRACT FROM AUTHOR]

This paper presents the zonal geochemistry and elasticity characteristics of gallium- and lithium-rich No. 6 coalbed in the Haerwusu mine and discusses interpretation methodologies of coal-hosted gallium and lithium resources using lab-measured samples and field-measured wireline logs. The results demonstrate that both coal-composition-based and elastic-parameter-based classifications yield similar results, categorizing the coalbed into subzones related to coal quality. Material compositions, elastic properties, critical metals, and host minerals exhibit zonal distribution characteristics within the ultrathick No. 6 coalbed. Three-class classifications significantly enhance correlations among host minerals, elastic parameters, and critical metals, albeit with differing trends among classes. In classes II and III (ultralow- and low-ash-yield coals), boehmite and kaolinite primarily host gallium and lithium, respectively. In class I (medium-ash-yield coal), gallium is associated with kaolinite, while lithium lacks specific mineral associations. Constrained by wireline logs, a rock physics modeling strategy is proposed to link mesoscale coal compositions to macroscale elastic responses. Moreover, explicit correlations between host minerals and critical metals are established, connecting macroscale elastic responses to microscale gallium and lithium enrichments and exploring interpretation methods of coal-hosted critical metals. Preferred lithium interpretation methods include compositional ternary plots and elastic parameter cross plots, while preferred gallium interpretation methods involve boehmite-gallium and elastic parameter-gallium fitting. These findings may contribute to understanding the enrichment mechanisms and interpretation technologies of coal-hosted critical metals in ultrathick low-rank coalbeds.

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

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

Rock mechanics parameters control the distribution of in situ stress and natural fractures, which is the key to sweet spot evaluation in reservoir engineering. Combined with the distribution of in situ stress, an experimental scheme of stress on rock physical parameters was designed. The results show that rock sonic velocity is extremely sensitive to water saturation under overburden pressure. At ultrasonic frequencies, when the water saturation increases from 0% to 80%, the P-wave velocity increases first and then decreases. When the water saturation continues to increase to 100%, the P-wave velocity increases. This is due to the effect of water saturation on the shear modulus. Saturation is negatively correlated with shear wave velocity and resistivity. Different minerals have different control effects on the rock P-S wave velocity ratio. Quartz content plays a dominant role, and the two are negatively correlated, followed by feldspar and clay, and the two are positively correlated with the P-S wave ratio. The confining pressure, axial compression, stress ratio and burial depth are positively correlated with the P-S wave and negatively correlated with the P-S wave ratio; in descending order, the influencing factors of stress on the petrophysical parameters are maximum stress ratio > confining pressure > axial pressure. [ABSTRACT FROM AUTHOR]

The present study based on petrophysical computations assess the conventional fuel resources of the Yageliemu Formation. The Yageliemu Formation was evaluated using log data from four wells (YK19, YK20, YK21, and YK32) and observed over the entire reservoir interval. Yageliemu Formation originates from the Lower Cretaceous reservoir, which is located in the Yakela gas condensate field, Kuqa Depression of Tarim Basin China. The studied gas bearing zones are primarily composed of sandstone, with small amounts of shale and clay contents. The petrophysical properties of the gas-bearing zones were carefully examined, which are rated to be better quality sand layers with average effective porosities varying from 7 to 10%, permeability varying from 3 to 8.6 mD, average water saturation values ranging from 43 to 59%, and the average range of gas saturation is 40–57%. The Yageliemu Formation cutoff outcomes for shale volume (Vsh), effective porosity, water saturation, and permeability were characterized at 40% and 5%, 65%, and 0.1 mD, respectively. Thomas Stieber model was used to successfully identify shale structural behavior in reservoirs and it revealed that the dominant shale is mainly laminated with a minor volume of structural and dispersive shale. Lithofacies and axial variations of reservoir properties are assessed by constructing self-organizing maps, isoparametric maps of the petrophysical properties, and litho-saturation cross-plots, respectively. The reservoir characteristics of the Yageliemu Formation demonstrate that the prospective region for hydrocarbons accumulation trends is in the southwestern and northwestern parts of the research area. The study techniques can be used in the Tarim Basin and similar basins around the world to estimate the petrophysical properties of oil and gas wells and comprehend reservoir prospects.

The present paper introduces a Legendre polynomials based interval inversion method for processing multi-borehole logging data. The method allows the determination of lateral changes of the layer-thicknesses together with the vertical and lateral variations of petrophysical parameters along a 2D cross-section of several boreholes. The method is assessed using noisy synthetic measurements of a petrophysical model made of two-layers structure related to hydrocarbon bearing formations. The numerical experiments aided to investigate the stability and convergence of the 2D interval inversion procedure. To ensure the accuracy and reliability of the inversion results, the misfit of data and model distance are tested, beside the calculation of estimation errors and correlation coefficients. A large amount of input data relative to the number of unknowns results in a high overdetermined ratio, consequently more precise estimates are obtained in stable and convergent procedure than in conventional local (1D) inversion schemes. The feasibility of the 2D interval inversion method is shown by analysing in-situ well logging data acquired in four wells situated in an Egyptian hydrocarbon field. [ABSTRACT FROM AUTHOR]

Rock mechanics parameters control the distribution of in situ stress and natural fractures, which is the key to sweet spot evaluation in reservoir engineering. Combined with the distribution of in situ stress, an experimental scheme of stress on rock physical parameters was designed. The results show that rock sonic velocity is extremely sensitive to water saturation under overburden pressure. At ultrasonic frequencies, when the water saturation increases from 0% to 80%, the P-wave velocity increases first and then decreases. When the water saturation continues to increase to 100%, the P-wave velocity increases. This is due to the effect of water saturation on the shear modulus. Saturation is negatively correlated with shear wave velocity and resistivity. Different minerals have different control effects on the rock P-S wave velocity ratio. Quartz content plays a dominant role, and the two are negatively correlated, followed by feldspar and clay, and the two are positively correlated with the P-S wave ratio. The confining pressure, axial compression, stress ratio and burial depth are positively correlated with the P-S wave and negatively correlated with the P-S wave ratio; in descending order, the influencing factors of stress on the petrophysical parameters are maximum stress ratio > confining pressure > axial pressure.

The present work deals with an interpretation of well log data (gamma ray (GR), resistivity, density, and neutron) from four wells, namely P-1, P-2, P-3 and P-4 in the study area of the Rio Del Rey basin. The well logs analysis indicates five potential sandstone reservoirs at the P-1, two at the P-2, four at the P-3 and six at the P-4. The neutron–density-GR logs highlight the sandstone gas reservoir characterized by high resistivity and crossover between neutron density. The neutron–density-GR cross-plot confirms the presence of sandstone containing hydrocarbons by a displacement of the cloud of points, from low to medium GR values, from the sandstone line to the left. Petrophysical parameters exhibit the value 12–41% for a volume of shale, 15–34% for effective porosity, 29–278 mD for permeability and 3–63% for water saturation. The three potential hydrocarbon reservoir saturation ranges from 22 to 45%. The study will contribute to future offshore oil and gas exploration and development in the Rio Del Rey basin, based on the geological and geophysical characteristics of the reservoirs delineated. [ABSTRACT FROM AUTHOR]

Abstract Petrophysical assessment of Facha Formation based on log data of six wells A1, A3, A4, A5, A8 and A13 recorded over the entire reservoir interval was established. Hakim Oil Field produces from the Lower Eocene Facha reservoir, which is located at the western side of Sirte basin. Limestone, dolostone and dolomitic limestone are the main lithologies of the Facha reservoir. This lithology is defined by neutron porosity—density cross-plot. Noteworthily, limestone increases in the lowermost intervals of the reservoir. Structurally, the field is traversed by three northwest–southeast faults. The shale of the Upper Cretaceous Sirte Formation is thought to be the source rock of the Facha Formation, whereas the seals are the limestone and anhydrite of the Lower Eocene Gir Formation. In this study, the Facha reservoir’s cutoff values were obtained from the cross-plots of the calculated shale volume, porosity and water saturation values accompanied with gamma ray log data and were set as 20%, 10% and 70%, respectively. Isoparametric maps for the thickness variation of net pay, average porosity, shale volume and water saturation were prepared, and the authors found out that the Facha Formation has promising reservoir characteristics in the area of study; a prospective region for oil accumulation trends is in the north and south of the study area.

Petrophysical assessment of Facha Formation based on log data of six wells A1, A3, A4, A5, A8 and A13 recorded over the entire reservoir interval was established. Hakim Oil Field produces from the Lower Eocene Facha reservoir, which is located at the western side of Sirte basin. Limestone, dolostone and dolomitic limestone are the main lithologies of the Facha reservoir. This lithology is defined by neutron porosity—density cross-plot. Noteworthily, limestone increases in the lowermost intervals of the reservoir. Structurally, the field is traversed by three northwest–southeast faults. The shale of the Upper Cretaceous Sirte Formation is thought to be the source rock of the Facha Formation, whereas the seals are the limestone and anhydrite of the Lower Eocene Gir Formation. In this study, the Facha reservoir's cutoff values were obtained from the cross-plots of the calculated shale volume, porosity and water saturation values accompanied with gamma ray log data and were set as 20%, 10% and 70%, respectively. Isoparametric maps for the thickness variation of net pay, average porosity, shale volume and water saturation were prepared, and the authors found out that the Facha Formation has promising reservoir characteristics in the area of study; a prospective region for oil accumulation trends is in the north and south of the study area. [ABSTRACT FROM AUTHOR]

An evolutionary approach is applied to solve the nonlinear well logging inverse problem. In the framework of the proposed interval inversion method, nuclear, sonic, and laterolog resistivity data measured at an arbitrary depth interval are jointly inverted, where the depth variation of porosity, water saturation, and shale volume is expanded into series using Legendre polynomials as basis functions. In the interval inversion procedure, the series expansion coefficients are estimated by using an adaptive float-encoded genetic algorithm. Since the solution of the inverse problem using traditional linear optimization tools highly depends on the selection of the initial model, a heuristic search is necessary to reduce the initial model dependence of the interval inversion procedure. The genetic inversion strategy used in interval inversion seeks the global extreme of the objective function and provides an estimate of the vertical distribution of petrophysical parameters, even starting the inversion procedure from extremely high distances from the optimum. For a faster computational process, after a couple of thousand generations, the genetic algorithm is replaced by some linear optimization steps. The added advantage of using the Marquardt algorithm is the possibility to characterize the accuracy of the series expansion coefficients and derived petrophysical properties. A Hungarian oil field example demonstrates the feasibility and stability of the improved interval inversion method. As a significance, the genetic inversion method does not require prior knowledge or strong restrictions on the values of petrophysical properties and gives highly reliable estimation results practically independent of the initial model and core information. [ABSTRACT FROM AUTHOR]

Many carbonate oil and gas reservoirs are characterized by the presence of secondary pores: vugs and fractures. To estimate the volume of oil and gas in carbonate rocks with double porosity, the information about secondary pore structure is required. In the present work we propose a simple and easy to code methodology to determine secondary pore types in carbonate sediments using acoustic well log data. The methodology is based on the comparison of the normalized differences between the calculated and measured in a borehole velocity of the compressional and shear waves. The results were obtained for the rocks with polymineral skeleton (limestone and dolomite). The mineral concentration is estimated by the solution of the inverse problem using the data obtained by a neutron, density, and PEF logging. The classification results were adjusted by using the micromechanical methods (the Kuster-Toksöz method and the Effective Medium Approximation (EMA)). Examples of the developed methodology application in the carbonate reservoirs are presented. • We proposed a simple methodology of the determination of the secondary porosity type. • The methodology is applied for carbonate sediments with multimineral skeleton. • The methodology was validated by using the log data for carbonate reservoirs in Mexico. • This information can be used for prediction of connectivity of secondary pore systems. [ABSTRACT FROM AUTHOR]

• A kinetics equation is proposed to describe CO 2 -water–rock interactions. • Bridging by mass loss, a kinetics calculation method is proposed for pore evolution. • Rock porosity is dominantly controlled by soluble minerals in reaction process. • Reaction extent of soluble minerals is linearly correlated with porosity increment. • Dissolution of soluble minerals and rock pore evolution are weakened by flow effect. Carbon capture and storage (CCS) technology is an important measure to reduce carbon emissions, and the safety of CCS projects largely depends on the physical and chemical processes of CO 2 -water–rock interactions in reservoirs. As the important petrophysical parameters of reservoir rocks, the change trends of pore structure parameters are usually ignored and thus difficult to quantitatively master. In this study, non-flow and flow interaction tests were performed under the premise of considering the flow effect of liquid environment. Based on chemical kinetics method, the reaction kinetics equation was first established, and the different reaction mechanisms of soluble and insoluble minerals were clarified. In flow interactions, the dissolution of soluble minerals is weakened and the precipitation of insoluble minerals is enhanced. The evolution trends of pore structure parameters were further analysed to find the inhibited pore evolution process by flow effect. A kinetics method was proposed to calculate the pore evolution process. The dominantly controlling effect of soluble minerals on the pore evolution process was illustrated by correlation analysis, and a prediction method for porosity increment was proposed based on the reaction extent of soluble minerals. Eventually, the CO 2 -water–rock interaction mechanism was clarified from the mineral level. [ABSTRACT FROM AUTHOR]

Porosity is considered as an important petrophysical parameter in characterizing reservoirs, calculating in-situ oil reserves, and production evaluation. Nowadays, using intelligent techniques has become a popular method for porosity estimation. Support vector machine (SVM) a new intelligent method with a great generalization potential of modeling non-linear relationships has been introduced for both regression (support vector regression (SVR)) and classification (support vector classification (SVC)) problems. In the current study, to estimate the porosity of a carbonate reservoir in one of Iran south oil fields from well log data, the SVR model is firstly constructed; then the performance achieved is compared to that of an artificial neural network (ANN) model with a multilayer perceptron (MLP) architecture as a well-known method to account for the reliability of SVR or the possible improvement made by SVR over ANN models. The results of this study show that by considering correlation coefficient and some statistical errors the performance of the SVR model slightly improves the ANN porosity predictions.

Based on the available well log data of six wells chosen in the North Qarun oil field in the Western Desert of Egypt, the petrophysical evaluation for the Lower Cretaceous Kharita Formation was accomplished. The lithology of Kharita Formation was analyzed using the neutron porosity-density and the neutron porosity-gamma ray crossplots as well as the litho-saturation plot. The petrophysical parameters, include shale volume, effective porosity, water saturation and hydrocarbon pore volume, were determined and traced laterally in the studied field through the iso-parametric maps. The lithology crossplots of the studied wells show that the sandstone is the main lithology of the Kharita Formation intercalated with some calcareous shale. The cutoff values of shale volume, porosity and water saturation for the productive hydrocarbon pay zones are defined to be 40%, 10% and 50%, respectively, which were determined, based on the applied crossplots approach and their limits. The iso-parametric contour maps for the average reservoir parameters; such as net-pay thickness, average porosity, shale volume, water saturation and the hydrocarbon pore volume were illustrated. From the present study, it is found that the Kharita Formation in the North Qarun oil field has promising reservoir characteristics, particularly in the northwestern part of the study area, which is considered as a prospective area for oil accumulation. [ABSTRACT FROM AUTHOR]

For feasibility studies of field development projects and management of time, risk, and cost, it is crucial to forecast the productivity of oil and gas wells. In this research a precise and comprehensive methodology is presented to estimate productivity in horizontal drilling. Petrophysical parameters of one of the Iranian oilfields including effective porosity, clay percentage, water saturation, and permeability were investigated in horizontal and vertical sections with specific intervals in all the reservoir spots using the well logging data. The seismic parameters of the reservoir including frequency, amplitude, and phase of the reflected seismic waves were also investigated. Petrophysical Reservoir Hydrocarbon Potential Index (RHPi)p and Seismic Reservoir Hydrocarbon Potential Index (RHPi)s were obtained by the combining of the petrophysical and seismic parameters, respectively. The former index cannot solely represent the hydrocarbon quality of the reservoir precisely. In ideal condition, the two indices must be equal for a specific section of the reservoir. Another index, the Average Reservoir Hydrocarbon Potential Index (RHPi)av, which is actually the average of the aforesaid indices, was defined. This index ensures high accuracy. By applying and generalizing (RHPi)av to the whole reservoir, another index known as the Well Efficiency Index (WEI) was obtained. This index can be used to estimate and correct the productivity of the designed horizontal wells before drilling, comparing actual productivity of vertical wells drilled in the oilfield. The result is a range of productivity with a particular safety factor that has a high degree of accuracy and precision. [ABSTRACT FROM AUTHOR]

The present study deals with the evaluation of rheological behavior of low-solids mud during drilling shale formation and its effect on the pay zone productivity. This study involves the preparation of shale samples (shale formation) required for the shale sloughing tests and preparation of plug samples (reservoir formation) required for the saturation tests. The shale analyzed by X-ray diffraction showed that the main constituents are montmorillonite, small amounts of kaolinite and smectite, with a little bit of illite recorded in a few samples. Also, the low-solids base mud was prepared in form unweighted then weighted by barrite and the rheological properties (density, apparent viscosity, plastic viscosity yield point, gel strength, and thixotropy) were determined for the two types; the weighted low-solids base mud was then circulated with the shale for 12, 24, 36, 48, and 60 hr using the roller oven device to determine the sloughing ratio of the shale and the rheological properties after circulation. This circulation showed that the shale sloughing ratio increased to more than 90%. Afterward, the core samples (reservoir rock) were prepared in the form of plugs according to the test requirements and their physical properties, including porosity, permeability, and resistivity, were determined through clean samples, and after saturation by low-solids mud and shaly low-solids mud, a petrographic study was carried out for the clean and saturated samples by making thin sections to show the change in the porosity. From these it was concluded that the rheological behavior of the low-solids mud during drilling shale formation affected caused formation damage and had an effect on the pay zone productivity. The recommendation for minimizing the shale affect and formation damage is to add specific chemicals to the low-solids mud system during the drilling. [ABSTRACT FROM AUTHOR]

• The Laoling Group was mainly sourced from the Longgang Block and Liaoji granitoids. • The Ji'an Group was mainly sourced from the Liaoji granitoids and Longgang Block. • The JLJB extends from Linjiang to Baishan and eastward to North Korea, beneath Quaternary basalts. • Geodynamic processes in the JLJB involved subduction, collision, and exhumation. The tectonic setting and depositional environments of the Laoling and Ji'an groups in the northeastern Jiao–Liao–Ji Belt, northeastern China, are controversial. These Paleoproterozoic stratigraphic units are exposed sporadically (in Baishan and Tonghua) beneath a thick cover of Quaternary basalts, meaning that only limited information can be obtained by traditional geological methods. Therefore, using geophysical techniques in this region is pertinent. Here we present new data on the petrophysical properties (density, magnetic susceptibility, and specific resistivity) obtained from 2D cross-gradient joint inversion profiles. The results allow us to establish the relationships between the Laoling and Ji'an groups, interpret the tectonic setting of deposition, and locate the subsurface margins of the Jiao–Liao–Ji Belt. Petrophysical parameters from the Dataishan Formation (density of 2.58 g/cm3, zero magnetic susceptibility, and specific resistance of 103.04 Ω m) indicate that these rocks were derived predominantly from the Longgang Block in the north. For the Zhenzhumen Formation, the petrophysical parameters (high density, weak magnetic susceptibility, and high specific resistivity) are consistent with deposition in a passive margin that received detrital material sediments from the Longgang Block and the Liaoji granitoids. The Mayihe and Huangchagou formations (intermediate to high density, strong magnetic susceptibility, and intermediate specific resistivity) were deposited closer to a magmatic arc, with the detritus derived from the Liaoji granitoids. The low to intermediate density, stronger magnetic susceptibility, and intermediate specific resistivity of the Huashan–Linjiang, Dalizi, and Dadongcha formations indicate that these rocks were deposited in a pre-orogenic setting, with the detritus derived from the Longgang Block, Liaoji granitoids, and other felsic igneous rocks. Based on the geophysical profiles, we conclude that the Jiao–Liao–Ji Belt extends under Quaternary basalt, from Linjiang to Baishan, and eastward towards North Korea. Two basin-controlling faults (F1 and F2) represent the northern and eastern boundaries between the Longgang Block and the Jiao–Liao–Ji Belt. We interpret geophysical anomalies and variations in the petrophysical parameters in the context of subduction and collision processes. [ABSTRACT FROM AUTHOR]