The present disclosure provides an edge and bottom water invasion simulation apparatus and method, a storage medium, and a product. A controller controls an inert gas to be injected into a first intermediate container, and stops the injection. The controller controls formation water to be injected into the first intermediate container, and stops the injection. The controller controls the first intermediate container to be communicated with a core holder, and adjusts a pressure of a back pressure valve, so that the formation water enters a core to simulate edge and bottom water invasion. In the present disclosure, by adding the inert gas and the formation water to the intermediate container, an infinite edge and bottom water with sufficient energy at an early stage of a water invasion and a limited edge and bottom water with lower energy at a later stage of the water invasion can be effectively simulated.

A method for the detection of hydrocarbon contamination in a sample is disclosed. The method includes contacting a sample with a molecular probe. The molecular probe has a photoluminescence which is environmentally sensitive. The photoluminescence from the molecular probe is collected. The method includes determining whether the photoluminescence is indicative of a hydrocarbon contaminated sample. A test strip for the detection of hydrocarbon contamination in a sample is also disclosed. The test strip includes a molecular probe embedded in a substrate and/or immobilized to the substrate, the molecular probe having a photoluminescence which is environmentally sensitive to hydrocarbon contaminated sample.

The present invention provides a method for forming a history of natural gas accumulation by using carbon isotopes by a pyrolysis experiment. The method includes: obtaining activation energy distribution and a frequency factor of light carbon methane; carrying out carbon isotope kinetics simulation of natural gas in a study area by using a spreadsheet function of Excel to obtain activation energy, a mass fraction and a frequency factor of heavy carbon methane; establishing a burial history and a thermal history of the study area based on geological data; and combining the activation energy distribution and frequency factor of the heavy carbon methane with the burial history and thermal history of the study area, and establishing an instantaneous curve, a cumulative curve and a stage cumulative curve of natural gas under geological conditions on a geologic time scale.

A method for determining maximum recoverable hydrocarbon (EMR) in a tight reservoir is disclosed. The method includes determining, based on downhole logs, a total measure of hydrocarbon amount within the tight reservoir, determining, by at least attributing fluid loss during core surfacing of the core sample to hydrocarbons, a non-recoverable measure of hydrocarbon amount within a core sample of the tight reservoir, and determining an EMR measure based on the total measure of hydrocarbon amount and the non-recoverable measure of hydrocarbon amount, wherein during the core surfacing pore pressure reduces from a reservoir condition to a surface condition.

An x-ray-based borehole fluid evaluation tool for evaluating the characteristics of a fluid located external to said tool in a borehole using x-ray backscatter imaging is disclosed, the tool including at least an x-ray source; a radiation shield to define the output faun of the produced x-rays into the borehole fluid outside of the tool housing; at least one collimated imaging detector to record x-ray backscatter images; sonde-dependent electronics; and a plurality of tool logic electronics and power supply units. A method of using an x-ray-based borehole fluid evaluation tool to evaluate the characteristics of a fluid through x-ray backscatter imaging is also disclosed, the method including at least producing x-rays in a shaped output; measuring the intensity of backscatter x-rays returning from the fluid to each pixel of one or more array imaging detectors; and converting intensity data from said pixels into characteristics of the wellbore fluids.

An object of the disclosure is to determine the remaining saturation of existing fluids in naturally fractured and/or homogeneous reservoirs, considering an unconventional tracer test, using the double tracer test method with pressure monitoring (PDTcMP®), which also integrates unused technical elements, in order to estimate more accurately the value of the remaining oil saturation (ROS) in naturally fractured reservoirs, unlike conventional methods used most commonly in homogeneous media. The disclosure substantially modifies the conventional tracer test, as it uses innovative technical elements, which reduce the uncertainty and/or ambiguity associated with conventional tracer tests, when they are applied in naturally fractured reservoirs.

Methods and systems, including computer programs encoded on a computer storage medium can be used for an integrated methodology that can be used by a computing system to automate processes for generating, and updating (e.g., in real-time), subsurface reservoir models. The methodology and automated approaches employ technologies relating to machine learning and artificial intelligence (AI) to process seismic data and information relating to seismic facies.

The present invention relates to a method of characterizing organic hydrocarbon compounds contained in a solid deposit of a geothermal plant, by measuring a quantity of organic hydrocarbon compounds released by a solid deposit sample during heating by pyrolysis according to a temperature sequence such that: from a temperature (T1) ranging between 50° C. and 120° C., the temperature of a rock sample is raised to a temperature (T2) ranging between 180° C. and 220° C. This temperature (T2) is then maintained for a predetermined duration. The temperature of the sample is raised to a temperature (T3) ranging between 330° C. and 370° C. This temperature (T3) is maintained for a predetermined duration. The temperature of the sample is thereafter raised to a temperature (T4) ranging between 630° C. and 670° C.

A method and system for approximating a predicted three-dimensional imbibition phase saturation profile from a measured three-dimensional drainage phase saturation profile, a derived one-dimensional drainage phase saturation profile, a measured one-dimensional imbibition phase saturation profile using a trained machine-learning algorithm are disclosed. A method for training of the machine learning algorithm is also disclosed.

The present invention provides a method for estimating hydrocarbon saturation of a hydrocarbon-bearing rock from a resistivity log and a rock image. The image is segmented to represent either a pore space or solid material in the rock. An image porosity is estimated from the segmented image, and a corrected porosity is determined to account for the sub-resolution porosity missing in the image of the rock. A corrected cementation exponent of the rock is determined from the image porosity and the corrected porosity and is used to estimate the hydrocarbon saturation. A backpropagation-enabled trained model can be used to segment the image. A backpropagation-enabled method can be used to estimate the hydrocarbon saturation using an image selected from a series of 2D projection images, 3D reconstructed images and combinations thereof.