An oil well production analyzing system receives production fluid samples from the oil well according to an automated sampling schedule. The fluid samples are taken from a pipeline through a sampling apparatus to obtain a representative sample. The representative sample flows into a circulation loop having a circulating pump, a water cut analyzer, and a cylindrical vessel, with interconnecting piping and actuated valves there between, with the actuated valves and the circulating pump controlled by a digital processor. Once a determination of the percentage of water and oil in the sample has been determined, the processor stops the circulating pump and activates a piston in the cylindrical vessel which sweeps the cylindrical vessel of any fluid contained in the vessel in preparation of receiving a subsequent fluid sample from the oil well.

A prediction method for coal and gas outburst based on comparing borehole gas flow curves includes the following steps: constructing a seam-crossing borehole in the coal seam, measuring or calculating gas flow corresponding to critical gas pressure P, which is a reference gas flow Q(t).sub.reference; performing linear regression on the reference gas flow Q(t).sub.reference to form a reference flow curve; constructing a predicted seam-crossing borehole in a predicted area, and directly testing a gas flow at each time t in a delayed manner, which is a predicted gas flow Q(t).sub.prediction; performing linear regression on the predicted gas flow Q(t).sub.prediction to form a predicted flow curve; and judging whether the predicted flow curve is above the reference flow curve or whether the predicted flow curve intersects with the reference flow curve, and judging whether the coal seam in the predicted area has a risk of coal and gas outburst.

A method can include flowing fluid from a formation from an inlet of a tool to an annulus; flowing spacer fluid from a conduit to the annulus; flowing the fluid and the spacer fluid in the annulus to a station; and collecting the fluid.

An apparatus, method, and sample vessel for recombining a sample fluid. The sample fluid is received in a sample vessel. Sample parameters are recreated in the sample vessel. The sample fluid is agitated within the sample vessel. Optical measurements of the sample fluid are performed within the sample vessel utilizing one or more optical sensors. A determination is made whether recombination is complete in response to the optical measurements of the sample fluid performed by the one or more optical sensors.

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.

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 a linear 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 linear inversion.

Systems and methods for determining the productivity indices for individual laterals of a completed multilateral well under commingled flow comprise a productivity index generator, zonal inflow control valves (ICVs), and a pressure downhole monitoring system (PDHMS). The completed multilateral well comprises a mother bore and a plurality of laterals extending from the mother bore in corresponding well zones of the mother bore. Each zonal ICV is configured to close for a shut-in period and open for an open period. The PDHMS is configured to generate real time pressure measurements for each well zone of the mother bore. The productivity index generator is communicatively coupled to the zonal ICVs and the PDHMS and is operable to determine a productivity index for individual laterals under commingled flow based on (i) the productivity index ratio of individual laterals under non-commingled flow and (ii) the global well productivity index under commingled flow.

A method includes positioning a downhole acquisition tool in a well-logging device in a wellbore in a geological formation, where the wellbore or the geological formation, or both contain a reservoir fluid. The method includes performing downhole fluid analysis using a downhole acquisition tool in the wellbore to determine a plurality of fluid properties associated with the reservoir fluid. The method includes generating a nonlinear predictive control model representative of the plurality of fluid properties based at least in part on the downhole fluid analysis. The method includes adjusting the nonlinear predictive control model based at least in part on an output representative of a pump flow control sequence at a first time interval and the plurality of fluid properties.

The present invention discloses a method for evaluating and preventing creep damage to conductivity of hydraulic fracture in gas reservoirs, comprising: (1) selecting a rock sample of target reservoir for creep experiment, and plotting ε-t curve of the rock sample during creep; (2) fitting the fractional Kelvin model with the ε-t curve of the rock sample during creep; (3) calculating the conductivity and permeability of hydraulic fracture considering creep damage; (4) numerically solving the productivity model, calculating the cumulative gas production of the gas well produced up to time t, and calculating the creep damage rate for cumulative production of the gas well; (5) repeating Steps (3) to (4), calculating the creep damage rate for cumulative production for the cases of hydraulic fracture sanding concentration N of 5 kg/m.sup.2, 7.5 kg/m.sup.2, 10 kg/m.sup.2, 12.5 kg/m.sup.2 and 15 kg/m.sup.2 respectively, plotting the creep damage chart of cumulative production.

Apparatus, systems, and methods may operate to correct measured voltage data for selected weak differential measurements to provide corrected voltage data. Additional activity may include adjusting the corrected voltage data to remove level shifts in the measured voltage data caused by downhole tool impedance to provide adjusted voltage data, converting the adjusted voltage data into apparent resistivity data, inverting the apparent resistivity data to determine true resistivity values for a geological formation, and operating a controlled device according to the true resistivity values for the geological formation. Additional apparatus, systems, and methods are disclosed.