Certain methods to determine wellbore relative permeability ratio from wellbore drilling data are described. A section of a wellbore is drilled in a subterranean zone including a subsurface reservoir in which hydrocarbons are entrapped. The hydrocarbons include a multiphase fluid including oil phase and water phase. A relevant suite of logs of rock in the section of the wellbore is determined. Water saturation is determined from the relevant suite of logs. A relative permeability ratio of the rock in the section to a flow of the oil phase and the water phase is determined. Using the relative permeability ratio, a flow rate of the oil phase or a flow rate of the water phase through the rock is determined.

Methods and systems for designing, monitoring, and/or performing acidizing treatments in subterranean formations are provided. A method comprises: determining a wellbore pressure and a fluid flow distribution for an acidizing fluid introduced into an interval of a well bore penetrating a portion of a subterranean formation; determining an optimum interstitial velocity for the acidizing fluid in the subterranean formation and an interstitial velocity of the acidizing fluid at a tip of a wormhole in the subterranean formation at a first flow rate at each of a plurality of depths; and if the interstitial velocity of the acidizing fluid at the tip of the wormhole is less than the optimum interstitial velocity at one or more of the plurality of depths, identifying a second flow rate for introducing the acidizing fluid into the interval of the well bore that is greater than the first flow rate.

A method of developing a predictive model for sand production from a wellbore includes receiving an indication of sand ingress at one or more production zones within a first wellbore using a sand monitoring system disposed within the first wellbore, detecting, using a pressure monitoring system, a pressure within the first wellbore while producing the one or more fluids and detecting the sand ingress, determining one or more geophysical properties of the one or more production zones of the first wellbore, and determining a model that correlates sand ingress at each of the one or more production zones with a plurality of variables. The sand ingress occurs while producing one or more fluids from the first wellbore.

Systems and methods include a computer-implemented method for characterizing low-permeability reservoirs by using numerical models. A numerical model modeling production of a well is prepared using reservoir data and well data. The numerical model is updated, including adjusting numerical model properties, until results of performing a quality assurance/quality control check indicate that the numerical model is within acceptable limits. Pressure derivatives are extracted from a transient test to create a functional numerical model. Simulations are run on the functional numerical model and reservoir features and properties are adjusted until acceptable results are achieved on: 1) a pressure match between pressures modeled in the functional numerical model and transient pressures of the well, and 2) a log-log plot derivative match between a pressure derivative of the functional numerical model and a pressure derivative of the transient pressures of the well. A simulation output that is based on the simulations is provided.

A method and a system to determine fracture properties during standard operations and injection tests. Fracture compliance, fracture closure pressure, and perforation friction can be determined using a combination of acoustic data, pressure decay data, and wellbore models. A method of automating and adjusting fracture design in real-time. A method and system to recover active, single active pulse data from a background noise dataset.

A method, system, and non-transitory computer readable medium storing instructions executable by a computer processor, the instructions comprising functionality for determining remediation categories for a plurality of wells include: obtaining, by a computer processor, a plurality of attributions for the plurality of wells; obtaining, by the computer processor, a set of weightages for each of the plurality of attributes for the plurality of wells; generating, by the computer processor, a first Well Health Index (WHI) set for a well among the plurality of wells; generating, by the computer processor, a second WHI set for the well; determining, by the computer processor, a sum of weightages of the second WHI set for the well; determining, by the computer processor, a remediation category among a plurality of remediation categories for the well based on the sum of weightages; and generating, by the computer processor, tracking notifications and action reports for the well.

A pressure-testing system for a tubular product. Preferably, the tubular product is a joint or a stand of production tubing. The pressure testing assembly includes a controller; a fluid reservoir configured to contain a test fluid; a pump in fluid communication with the fluid reservoir; a fluid hose having a first end configured to receive the test fluid from the reservoir, and a second end configured to be fluidically connected to a hydrotest tool for the tubular product; and a transducer. The transducer sends signals to the controller indicative of pressure within the fluid hose. The controller is programmed to automatically (i) store a pressure threshold value (T) and (ii) store a pressure test value (P.sub.T) such that when pressure in the fluid hose reaches (T) or when pressure in the fluid hose reaches (P.sub.T), the controller sends a signal to a diverter to divert a direction of fluid being pumped so that fluid is no longer pumped into tubular product.

Methods for interpreting pressure transient tests and predicting future production for a well are provided. In one embodiment, a method for predicting future production includes beginning a pressure transient test within a well at a wellsite and obtaining pressure measurements of well fluid during the pressure transient test. The method can also include using the obtained pressure measurements to determine probabilistic estimates of input parameters of a pressure transient reservoir model while continuing the pressure transient test. Future production from the well can then be estimated based on the probabilistic estimates of the input parameters. Other methods and systems are also disclosed.

A system and method of enhancing operation of hydraulic fracturing equipment at a hydraulic fracturing wellsite may include determining if a hydraulic fracturing stage profiles are available for use for hydraulic fracturing equipment at a wellsite. The method may include prompting an acceptance or amendment of one of the hydraulic fracturing stage profiles for a hydraulic fracturing pumping stage. The method may include, in response to an amendment of one of the hydraulic fracturing stage profiles, prompting acceptance of the amended hydraulic fracturing stage profile as the current hydraulic fracturing stage profile for use in association with the controller. The method may include, when a hydraulic fracturing stage profile is not available, prompting configuration of hydraulic fracturing pumping stage parameters for the current hydraulic fracturing stage profile. The method may include storing the current hydraulic fracturing stage profile as the previous hydraulic fracturing stage profile in association with the controller.

Disclosed are methods, systems, and computer-readable medium to perform operations including: generating, based on production data for a wellbore, (i) a water-oil-ratio with respect to time (WOR) dataset for the wellbore, (ii) a time-derivative dataset (WOR′) of the WOR dataset; generating a WOR log-log plot of the WOR dataset and a WOR′ log-log plot of the WOR′ dataset; identifying at least one trend in the WOR log-log plot and the WOR′ log-log plot; determining, based on the at least one identified trend, a first type of water breakthrough; generating, based on pressure data from a build-up pressure test in the wellbore, a log-log plot of time-derivative pressure data with respect to time (P′); determining, based on the P′ log-log plot, a second type of water breakthrough; correlating the first and second type of water breakthrough; and determining, based on the correlation, whether to perform a water treatment for the wellbore.