1664 results about "Lithology" patented technology

Methods and systems are described for improved drilling operations through the use of real-time drilling data to predict bit wear, lithology, pore pressure, a rotating friction coefficient, permeability, and cost in real-time and to adjust drilling parameters in real-time based on the predictions. The real-time lithology prediction is made by processing the real-time drilling data through a multilayer neural network. The real-time bit wear prediction is made by using the real-time drilling data to predict a bit efficiency factor and to detect changes in the bit efficiency factor over time. These predictions may be used to adjust drilling parameters in the drilling operation in real-time, subject to override by the operator. The methods and systems may also include determining various downhole hydraulics parameters and a rotary friction factor. Historical data may be used in combination with real-time data to provide expert system assistance and to identify safety concerns.

An interpretation method and system for NMR echo-train data in thinly laminated sequences. The invention uses geological information obtained at higher vertical resolution, such as using Electric Micro Imaging, to enhance the vertical resolution of echo-train data, and thus avoids log interpretations in which the hydrocarbon potential of the formation can be misread because low resolution logs tend to provide an average description of the formation. Such averaging is especially problematic in thinly laminated sequences that consist of highly permeable and porous sand layers and less permeable silt or essentially impermeable shale layers. In a preferred embodiment, using the additional high-resolution formation information one can estimate the typical T2-spectra of lithological laminae, and significantly enhance the permeability estimate in the laminated sequences. The method and system are applicable to any temporal data from other logging tools, such as the thermal neutron decay log and others. The system and method enable proper evaluation of the high potential of thinly laminated formations, which may otherwise be overlooked as low permeable formations.

The invention is direction and position drill-following survey apparatus comprising a drill collar, two V slots, metal shielding layer, tow gamma sensor, three-axis acceleration sensor, signal processing circuit module, high pressure sealing cover board, boring liquor conducting channel, upper slip ring connector, lower slip ring connector, wire hole. The invention integrated gamma survey and directional survey in just a short section which enables the drill not only survey the rock properties real-timely, but also tell the upper and lower rock characteristics when boring well., so to effectively find out the upper cover layer of the storage layer and seize the best timing entering the oil storage layer. Moreover, meanwhile assorting the upper and lower rock properties, the direction and drill status also can be obtained without any delay, which, facilitating adjusting the well boring track according to the geographic data and manage the drill travels a best track underground among the oil storage. The invention is suitable for geological guiding in fossil engineering.

Apparatuses and methods suitable for (i) measuring lithological or petro-physical properties of reservoir core sample including shale rock; (ii) evaluating the degree of formation damage caused by foreign fluid into formation; (iii) conducting dynamic experiments, such as water flooding, chemical solution flooding, and supercritical CO₂ injection to displacing oil tests; (iv) simulating physical radial flow experiments using reservoir core sample(s) at conditions of temperature up to 150° C. and pressure up to 6000 psi, are provided involving radial flow through the core sample(s) having at least partially hollow centers in an axial direction, up to annular axial cross-sections.

The invention discloses a method for distinguishing a reservoir fluid type by adopting resistivity data, relating to the technological field of petroleum and gas logging, geology and core test analysis. The method comprises the following steps of: a. logging by utilizing core data scales and accurately calculating reservoir shale content, rock constituent and porosity; b. eliminating the influence of rock characters and the porosity on resistivity; c. utilizing a core test to obtain the parameters of m, a, n and b reflecting a pore structure, calculating the resistivity lower limit RR of an air layer and eliminating the influence of the pore structure on the resistivity; and d. distinguishing the reservoir fluid type by comparing a deep-induction and deep- lateral resistivity value RT andthe resistivity lower limit RR of the air layer obtained in the step c. The invention eliminates the influence of non-fluid factors of the rock characters, the porosity, the pore structure and the like on the resistivity, and maintains and utilizes the response characteristics of fluids with different resistivities so as to greatly enhance the coincidence rate for distinguishing the reservoir fluid type.

The invention discloses a lithology identification method. The lithology identification method comprises the steps that firstly, conventional three-porosity (sound waves, density and neutrons) logging measured values of N rock core samples are obtained through the steps of thin section authentication, X-ray diffraction analysis, rock core true depth determination and the like; secondly, the relative distance between two parameters of conventional three-porosity logging is obtained, and the quantitative relation between the relative distance of the two parameters and primary mineral components obtained through X-ray diffraction total rock analysis is obtained according to the relative distance of the two parameters and the mineral components of the N rock core samples; thirdly, rock classification based on the relative distance of the two parameters is established and can be applied to lithology identification of fine grain sedimentary facies area logging, and continuous lithology identification can be carried out on well stratums without core sampled.

Methods and systems are provided for displaying and forecasting the lithology and wellbore conditions to be encountered while conducting drill string operations are conducted in a wellbore. A method and system is described for predicting and modeling lithology while operating a drill string in a wellbore, comprising: developing a 3-D lithological model of a subsurface area; projecting a well path through said subsurface area; determining an open cylinder lithology display of said projected well path; and recording said determined open cylinder display. The open cylinder lithology display (the Predictive Stratigraphy Image) may be displayed with geological or structural cross-sections to compare the well path and the predicted well path, with the actual subsurface environment. Data acquired during drilling operations can be used in real time to update the model or the Predictive Stratigraphy Image, and the results compared with Predictive Image Logs and other wellbore images and data.

The invention discloses a method for judging the reservoir fluid type of a difference between density porosity and neutron porosity and relates to the technical fields of oil and gas logging and geology and core test analysis. The method comprises the following steps: 1) accurately calculating the shale content, the rock composition, the density porosity and the neutron porosity of a reservoir bycore data calibrating logging and logging data environmental correction; 2) removing the influence of factors of lithology, well diameter and mud invasion on density and neutron data; and 3) establishing standards for judging the reservoir fluid type by utilizing the response difference of the density and the neutron data to gas and formation water and by comparing the values of the density porosity and the neutron porosity. When the invention judges the reservoir fluid type by utilizing the density and the neutron data, non-fluid influencing factors, such as lithology, borehole conditions, mud invasion and the like are removed, therefore, influence features of different fluids to the density and the neutron data can be truly reflected, and the coincidence rate for judging the reservoir fluid type can be enhanced to above 90 percent from the existing 70 percent.

The invention belongs to the technical field of oil gas and coal-bed gas seismic exploration and development, and in particular relates to a reservoir sedimentary evolution analysis method in the exploration and development process. The method is used for providing reliable basic data for optimizing favorable target bed series and zone for oil gas and coal-bed gas exploration and development. In the method, sedimentary characteristics of reservoirs are analyzed by a three-dimensional seismic attribute data body, and high-resolution sequence stratigraphic principle and method, a seismic attribute analysis method and a pattern recognition method are applied; and a K-mean clustering algorithm is adopted, and the analysis process of sedimentary characteristics and sedimentary evolution of a sedimentary formation unit is performed under the control of a sedimentary isochronous interface. The method is used for assisting in reservoir sedimentary evolution research work in the exploration and development process of oil gas including unconventional oil gas, guiding the description of sedimentary characteristics of fine reservoirs of lithologic and stratigraphic trapped oil gas reservoirs, and providing the reliable basic data for optimizing the favorable target bed series and zone for the oil gas and coal-bed gas exploration and development.

The invention relates to a method for evaluating the organic carbon content of shale. The method comprises the steps that logging information is obtained and layer sections of the shale are obtained through division; lithology correction coefficients and radioactivity correction coefficients are obtained and corrected log response characteristic values are obtained; organic carbon content calculation functions of shale unit layer sections are established and the calculation function of the organic carbon content of each shale unit layer section is obtained; according to the determined organic carbon content calculation function, the organic carbon content of each shale unit layer section is calculated. According to the method for evaluating the organic carbon content of the shale, the defect that an organic carbon content result in the prior art is large in error is overcome, the organic carbon content in a stratum can be accurately and reliably evaluated, and therefore effective technical supports are provided for exploration and development of shale oil gas.

The invention relates to a method for identifying the lithology of volcanic rock. The method comprises the following steps of: determining the types of rock needing lithological identification; calculating the content of each element in stratigraphic rock in percentage by weight by using the theory of oxygen closed mold on the basis of elemental capture spectroscopy logging information; classifying the lithology of volcanic rock by using a silicon-alkali classification method; extracting the rock structure information of different classes of lithology of volcanic rock on the basis of imaging logging information in combination with oilfield on-site coring analysis and geologic description; combining the rock components calculated according to elemental capture spectroscopy logging with therock structure information determined according to the imaging logging information together and converting a TAS two-dimensional plane into a three-dimensional plane by using the rock structure information as a third dimension scale; and realizing three-dimensional volcanic rock lithological identification by using an SVM (Support Vector Machine) method. By adopting the method, the coincidence rate of lithological identification can be improved to reach more than 90%, which is 10 times that of the traditional method.

Maximum and minimum horizontal stresses, and horizontal to overburden stress ratio, are estimated using radial profiles of shear moduli. Inversion enables estimation of maximum and minimum horizontal stresses using radial profiles of three shear moduli associated with an orthogonal set of axes defined by the three principal stress directions. Differences in the far-field shear moduli are inverted together with two difference equations obtained from the radial profiles of the dipole shear moduli C₄₄ and C₅₅, and borehole stresses in the near-wellbore region. The horizontal to overburden stress ratio is estimated using differences in the compressional, dipole shear, and Stoneley shear slownesses at two depths in the same lithology interval where the formation exhibits azimuthal isotropy in cross-dipole dispersions, implying that horizontal stresses are nearly the same at all azimuths. The overburden to horizontal stress ratio in a formation with axial heterogeneity may also be estimated using the far-field Stoneley shear modulus C₆₆ and dipole shear modulus C₅₅ together with the radial variation of the dipole shear modulus C₅₅ caused by near-wellbore stress concentrations.

The invention relates to a multi-parameter logging method while drilling based on a controllable neutron source, which includes the steps of utilizing a multi-detector measuring system consisting of the D-T controllable neutron source, two thermal neutrons and two gamma detectors, sufficiently utilizing fast neutrons transmitted by the controllable neutron source to militate with atomic nucleuses of formation elements by means of special pulse and measuring timing sequence design, recording gamma energy spectrums, gamma time spectrums and thermal neutron time spectrums at different positions, and performing simultaneous measurement of multiple parameters such as formation density, formation porosity, formation fluid saturation, formation element content and the like with a nuclear logging instrument in a drilling process by means of different spectral resolution and data processing, so that valuation on formation lithology, formation porosity and formation fluid saturation while drilling are realized, the same parameter of the formation porosity and the formation fluid saturation can be measured by various methods, logging interpretation ambiguity is decreased, and accuracy and reliability of logging data interpretation are enhanced.

Method for gradually modifying a geological model representative of an underground reservoir so as to respect fixed average proportions of these lithologic facies.

A group of facies referred to as selection and a subgroup of facies referred to as association are selected. A transformation parameter is defined by the ratio between the average proportions of the facies of the association and those of the selection. Within the context of history matching, a difference between measured dynamic data values and values calculated by means of a flow simulator from the geological model is measured. An optimization algorithm is used to deduce therefrom a new value for the transformation parameter that minimizes this difference and this transformation is applied to the lithologic facies of the selection. The modification can be applied to the entire model or to a given zone.

The invention discloses a method for judging the fluid type of a reservoir through an acoustic porosity-neutron porosity differential, which relates to the technical field of oil and gas logging, geology and core test analysis. The method comprises the following steps: 1) accurately calculating shale content, rock compositions, acoustic porosity and neutron porosity of the reservoir through core data calibration logging and logging data environment correction; 2) excluding the influence of factors such as lithology, borehole diameter and mud invasion on an acoustic transit time and neutron data; and 3) establishing a standard for judging the fluid type of the reservoir by comparing the magnitude of the acoustic porosity and the neutron porosity and using the response difference of the acoustic transit time and the neutron data to the gas and formation water. In the method, non-fluid influence factors such as the lithology, borehole conditions, mud invasion and the like are excluded when the fluid type of the reservoir is judged, so the characteristics of the influence of different fluids on the acoustic transit time and the neutron data can be grasped truly, and the coincidence rate of judging the fluid type of the reservoir is improved from 70 percent currently to over 90 percent.