The present disclosure relates to methods and systems for oil and gas field production management. An example system includes a production site and a production sensor configured to obtain information about a process parameter associated with the production site. The system also includes an on-site chemical tank and a mobile delivery vehicle with a chemical delivery system. The chemical delivery system is configured to dispense a chemical. The system also includes a controller that carries out operations, which include receiving, from the production sensor, information indicative of a process parameter value associated with the production site and determining, based on the received information, a chemical delivery request. The operations also include, in response to determining the chemical delivery request, routing the mobile delivery vehicle to the production site and causing the chemical delivery system to dispense the chemical to the on-site chemical tank according to the chemical delivery request.

A method may include drilling a wellbore, the wellbore intersecting a shale formation at an interval of the shale formation and casing at least a portion of the wellbore. The method may also include perforating the casing at the interval to fluidly couple the interval and the wellbore, and liberating free and absorbed gas entrapped within the interval. In addition, the method may include solubilizing in the wellbore fluid the free and absorbed gas, forming a plume comprising solubilized gas, and determining an identity and amount of solubilized gas in the plume.

A method of probabilistically estimating a velocity of a plunger of a beam pump may comprise continuously monitoring well acoustics using a plurality of passive acoustic sensors attached to external structures of the beam pump; digitizing outputs of the plurality of passive acoustic sensors and sending the digitized outputs to a computing device for storage and processing; and using the digitized outputs of the plurality of passive acoustic sensors, estimating a probability of the velocity of the plunger using a hidden Markov model (HMM) to represent a probability of a position and the probability of the velocity of the plunger, the HMM comprising a state space model and an observational model.

Provided are embodiments for hydrocarbon reservoir development that include the following: identifying proposed well locations within a reservoir boundary, for each location, developing a well plan by: (a) identifying layers of the reservoir located below the proposed location; (b) iteratively assessing the layers (from deepest to shallowest) to identify a deepest “suitable” layer that is not dry, congested, or unsuitable for gas production; and (c) performing the following for the identified layer and the location: (i) determining a borehole configuration for the location; (ii) determining a completion type for the location; and (iii) determining a stimulation treatment for the location, where a well plan for the location (e.g., for use in developing the reservoir) is generated that specifies some or all of a well location, the target layer, a borehole configuration, a completion type, and a stimulation treatment that corresponds to those determined for the proposed well location.

Systems and methods include a computer-implemented method for predicting values. A numerical simulation model is generated based on observed production rates and flowing pressure and build-up (FPBU) test rates. A simulated diagnostic plot is generated using simulated FPBU data extracted from the numerical simulation model. Simulation model properties of the numerical simulation model are adjusted until the simulated diagnostic plot matches within a tolerance to an observed FPBU diagnostic plot. Predicted values including a static pressure, a water cut, and a gas-oil rate (GOR) are predicted using the simulated FPBU data. Observed data of a reservoir is reviewed and quality-checked based on comparing the predicted values within a tolerance of the observed data.

An apparatus for use in fracturing wells includes a body defining and coupled to a wellhead of a well extending through a subsurface formation with the flow path being in communication with a wellbore of the well. The apparatus includes a flow meter in communication with the flow path and configured to measure a flow attribute of fluid from the wellbore along the flow path. The apparatus further includes a computing device communicatively coupled to the flow meter. The computing device is operable to receive a flow attribute measurement from the flow meter and to transmit an indicator in response to determining that the flow attribute measurement indicates interaction of a fracture in the subsurface formation with the well.

Provided herein are portable apparatus as well as methods of analyzing a fluid using these portable apparatus. In some embodiments, the injection fluid can contain a polymer, but a polymer is not necessary. For example, the portable apparatus and methods may be used to determine viscosity, long term injectivity, filter ratio, or any combination thereof of the injection fluid. Advantageously, the surrogate core is temperature controlled.

Systems and methods include a method providing automated production optimization for smart well completions using real-time nodal analysis including comingled production calibration. Real-time well rates and flowing bottom-hole pressure data are collected at various choke settings for multiple flow conditions for each lateral of a multilateral well during regular field optimization procedures. Surface and downhole pressures and production metrics for each of the laterals are recorded for one lateral at a time during production of the well. Flowing parameters of individual laterals are estimated using the multilateral well production model. An optimum pressure drop across each downhole valve is determined using the multilateral well production model. Each lateral of the multilateral well is calibrated during the commingled production at various choke valves settings. The calibrating is done using the multilateral well production model, based at least in part on the optimum pressure drop across each downhole valve.

A system can calculate estimated strain data for a fracture in a geological formation at each of a plurality of selected locations detectable by a strain measurement device. The system can receive real strain data from the strain measurement device for the geological formation. The system can perform an inversion to determine a probable distribution of fluid volume and hydraulic fracture orientation in the geological formation based on the estimated strain data and real strain data. The system can determine adjustments for a fracturing operation based on the inversion.

This disclosure relates to a method and a system for sequestering carbon-containing materials in underground wells. An example method includes: obtaining a material comprising a carbon-containing liquid; optionally testing the material for compatibility with an underground well; optionally adjusting a property of the material to improve the compatibility; and providing the material for injection into the underground well.