An apparatus to test a drilling fluid in a laboratory includes a test cell configured to test the fluid to determine a Sag Factor of the fluid. The test cell may be heated with a heating jacket to a predefined temperature. A plurality of densitometers are configured to continuously measure a density of the fluid circulating in the test cell. A computing device processes the density measurements to determine a Sag Factor of the drilling fluid.

A method includes installing a measurement device on the injection wellhead, injecting a fluid into the injection well at a plurality of injection rates using a computer processor, measuring an injection bottom hole pressure at each injection rate to determine a plurality of injection bottom hole pressures using the computer processor, determining a relationship between the plurality of injection rates and the plurality of injection bottom hole pressures using the computer processor, and determining an injectivity index of the injection well using the relationship and the computer processor.

Systems and methods include a computer-implemented method for determining an integrated surface-downhole integrity score for a natural flow oil well. Wellness surface parameters of a natural flow oil well are determined. Wellness downhole parameters for the natural flow oil well are determined, including parameters indicating well integrity and tubing/casing conditions. An integrated surface-downhole integrity score is determined using the wellness surface parameters and the wellness downhole parameters. An alert is provided for presentation to an operator in a user interface. The alert is provided in response to the integrated surface-downhole integrity score exceeding a threshold.

A drainage bottle apparatus includes a cylindrical body portion with a base, a neck portion, a receptor opening located at a rim, a first and a second threaded inner perimeter surface, a removable sieve having a sieve outer perimeter rim thread, and a sieve base. The sieve outer perimeter rim thread mates with the second threaded inner perimeter surface. A method for extracting a rock plug sample includes using the drainage bottle apparatus in combination with a sample jar containing a rock plug sample and a liquid material. The sample jar includes a sample jar outer perimeter surface thread that mates with the first threaded inner perimeter surface of the neck portion and is turned over so as to drain the liquid material thereby separating the liquid material from the rock plug sample and the rock plug sample, now dried, may be extracted.

A method of detecting an amine-based additive in a wellbore servicing fluid (WSF) comprising contacting an aliquot of WSF with an amine detector compound and an aqueous salt solution to form a detection solution; wherein the aqueous salt solution comprises an inorganic salt and organic carboxylate salt; wherein the WSF comprises the amine-based additive; and wherein the detection solution is characterized by at least one absorption peak wavelength in the range of 380-760 nm; detecting an absorption intensity for detection solution at a wavelength within about ±20% of the at least one absorption peak wavelength; comparing the absorption intensity of detection solution at the wavelength within about ±20% of the at least one absorption peak wavelength with a target absorption intensity of amine-based additive to determine the amount of amine-based additive in WSF; and comparing the amount of amine-based additive in WSF with a target amount of amine-based additive.

A method of detecting an amine-based additive in a wellbore servicing fluid (WSF) comprising contacting an aliquot of WSF with an amine detector compound and an aqueous salt solution to form a detection solution; wherein the aqueous salt solution comprises an inorganic salt and organic carboxylate salt; wherein the WSF comprises the amine-based additive; and wherein the detection solution is characterized by at least one absorption peak wavelength in the range of 380-760 nm; detecting an absorption intensity for detection solution at a wavelength within about ±20% of the at least one absorption peak wavelength; comparing the absorption intensity of detection solution at the wavelength within about ±20% of the at least one absorption peak wavelength with a target absorption intensity of amine-based additive to determine the amount of amine-based additive in WSF; and comparing the amount of amine-based additive in WSF with a target amount of amine-based additive.

The present disclosure relates to a prediction method for constant production decline of a water-producing gas well in a highly heterogeneous reservoir. The prediction method mainly includes: collecting related data of a target water-producing gas well, fitting to obtain a water-drive constant and a water invasion constant, fitting dynamic reserves by adopting a Blasingame plotting method, conducting fitting by adopting a dual-medium model to obtain an elastic storativity ratio and an interporosity flow coefficient, calculating a reservoir heterogeneity coefficient, obtaining a flowing bottomhole pressure at the later stage of stable production, calculating formation pressure of a new day through quantitative production of the target water-producing gas well with 1 day as an iteration stride, performing iteration until the formation pressure is less than or equal to the formation pressure at the end of stable production, and drawing a prediction curve about constant production decline of the target water-producing gas well.

The disclosure provides a pump system including a pump, a gas relief valve coupled to the pump, a motor configured to turn the pump, and a sensor configured to measure a parameter of at least one of a fluid or the pump system. The gas relief valve includes an actuator and a rotary disk system, and the rotary disk system includes a stationary disk and a rotary disk. The actuator is rotationally coupled to the rotary disk, and in a first position, the gas relief valve directs a flow of a fluid into a production tubing and in a second position, the gas relief valve directs the flow of the fluid into an annulus of a wellbore.

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.

A method may comprise forming a data matrix, extracting chromatographs of a mud filtrate and a formation fluid, extracting concentration profiles of the mud filtrate and the formation fluid, and decomposing a data set on an information handling machine using a bilinear model. A system may comprise a downhole fluid sampling tool and an information handling tool. The downhole fluid sampling tool may comprise one or more multi-chamber sections, one or more fluid module sections, one or more gas chromatographers, wherein the one or more gas chromatographers are disposed in the one or more fluid module sections, and an information handling system.