Provided are methods and systems for monitoring and modifying stimulation operations in a reservoir. In particular, the methods and systems utilize a downhole telemetry system, such as a network of sensors and downhole wireless communication nodes, to monitor various stimulation operations.

A method and apparatus are provided for determining movement of a fluid into or out of a subsurface wellbore, to thereby enable accurate allocation of fluids being produced by or injected into each of several zones of the wellbore. A temperature change is effected in the fluid in a semi-continuous or pulsed manner at one or more locations in the wellbore. A temperature of the fluid is measured at one or more sensing locations downstream of the location of the temperature change. A time of flight model is used to determine, for a plurality of points of interest, a fluid flow direction, bulk flow rate and/or a cumulative flow rate contribution.

A method and apparatus are provided for determining movement of a fluid into or out of a subsurface wellbore, to thereby enable accurate allocation of fluids being produced by or injected into each of several zones of the wellbore. A temperature change is effected in the fluid in a semi-continuous or pulsed manner at one or more locations in the wellbore. A temperature of the fluid is measured at one or more sensing locations downstream of the location of the temperature change. A time of flight model is used to determine, for a plurality of points of interest, a fluid flow direction, bulk flow rate and/or a cumulative flow rate contribution.

The invention relates to oil and gas production industry and can be used in production well logging operations. The method of determining a production well flow (production) profile in terms of hydrodynamic characteristics of individual reservoir units (their productivities and far-field reservoir pressures) in a multilayer reservoir includes temperature T.sub.f.sup.(1) and bottomhole pressure p.sub.b.sup.(1) measurements along the wellbore after the well has been producing for a long time at a known constant rate in a quasi-stationary regime, after which the rate is changed by a predetermined value for a period sufficient for a new quasi-stationary flow regime to set in, and then temperature T.sub.f.sup.(2) and bottomhole pressure p.sub.b.sup.(2) measurements along the wellbore are repeated. Whenever necessary and practicable, additional temperature and bottomhole pressure measurements along the wellbore are performed in different well-operation regimes, at different total flow rates. Then the reservoir pressure p.sub.l.sup.ex and productivity K.sub.l are estimated and flow rates V.sub.l are determined for each l-th unit (l=1, 2, . . . L, where L is the top layer number) in each well-operation (production) regime on the basis of bottomhole pressure and temperature measurement data, with the total production rates of the well in all logging regimes being known, by solving the system algebraic equations, starting from the topmost layer L (l=L, . . . , 2, 1).

C.sub.lQ.sub.l(T.sup.∧.sub.fl−T.sup.∨.sub.fl)=K.sub.l(p.sub.l.sup.ex−p.sub.bl)(T.sub.l.sup.ex−T.sup.∨.sub.fl+ε.sub.fl(p.sub.l.sup.ex−p.sub.bl)),

V.sub.l=K.sub.l(p.sub.l.sup.ex−p.sub.bl),

where ε.sub.fl is effective (non-stationary) Joule-Thomson coefficient;
T.sub.l.sup.ex—the average geothermal temperature across the l-th layer;
T.sup.∨.sub.fl—the flowing temperature at the lower boundary of the l-th layer;
T.sup.∧.sub.fl—the resulting flowing temperature at the top of the l-th layer;
C.sub.l—the ratio of the volumetric heat capacity of flow above the top of the l-th layer and that of the flow entering the well from the l-th layer;
T.sub.cl—the mean mixing temperature of the fluid flow from the l-th layer;
Q.sub.l—the total cumulative flow rate of the l-th layer and all the

The invention relates to oil and gas production industry and can be used in production well logging operations. The method of determining a production well flow (production) profile in terms of hydrodynamic characteristics of individual reservoir units (their productivities and far-field reservoir pressures) in a multilayer reservoir includes temperature T.sub.f.sup.(1) and bottomhole pressure p.sub.b.sup.(1) measurements along the wellbore after the well has been producing for a long time at a known constant rate in a quasi-stationary regime, after which the rate is changed by a predetermined value for a period sufficient for a new quasi-stationary flow regime to set in, and then temperature T.sub.f.sup.(2) and bottomhole pressure p.sub.b.sup.(2) measurements along the wellbore are repeated. Whenever necessary and practicable, additional temperature and bottomhole pressure measurements along the wellbore are performed in different well-operation regimes, at different total flow rates. Then the reservoir pressure p.sub.l.sup.ex and productivity K.sub.l are estimated and flow rates V.sub.l are determined for each l-th unit (l=1, 2, . . . L, where L is the top layer number) in each well-operation (production) regime on the basis of bottomhole pressure and temperature measurement data, with the total production rates of the well in all logging regimes being known, by solving the system algebraic equations, starting from the topmost layer L (l=L, . . . , 2, 1).

C.sub.lQ.sub.l(T.sup.∧.sub.fl−T.sup.∨.sub.fl)=K.sub.l(p.sub.l.sup.ex−p.sub.bl)(T.sub.l.sup.ex−T.sup.∨.sub.fl+ε.sub.fl(p.sub.l.sup.ex−p.sub.bl)),

V.sub.l=K.sub.l(p.sub.l.sup.ex−p.sub.bl),

where ε.sub.fl is effective (non-stationary) Joule-Thomson coefficient;
T.sub.l.sup.ex—the average geothermal temperature across the l-th layer;
T.sup.∨.sub.fl—the flowing temperature at the lower boundary of the l-th layer;
T.sup.∧.sub.fl—the resulting flowing temperature at the top of the l-th layer;
C.sub.l—the ratio of the volumetric heat capacity of flow above the top of the l-th layer and that of the flow entering the well from the l-th layer;
T.sub.cl—the mean mixing temperature of the fluid flow from the l-th layer;
Q.sub.l—the total cumulative flow rate of the l-th layer and all the

Methods and systems for monitoring an annulus pressure of a well. The method includes performing periodic surveys to monitor an annulus pressure of the well, determining the annulus pressure of the well over a period of time, comparing the annulus pressure to a Maximum Allowable Wellhead Operating Pressure (MAWOP), and generating a decision on whether the well is a workover candidate based on results of the comparison. The system includes a collecting tool that performs periodic surveys to monitor an annulus pressure of the well, determines the annulus pressure of the well over a period of time, and broadcasts information relating to the periodic surveys. The system further includes a processor that obtains the information relating the periodic surveys, compares the annulus pressure to a Maximum Allowable Wellhead Operating Pressure (MAWOP), and generates a decision on whether the well is a workover candidate based on the results of the comparison.

Methods and systems for monitoring an annulus pressure of a well. The method includes performing periodic surveys to monitor an annulus pressure of the well, determining the annulus pressure of the well over a period of time, comparing the annulus pressure to a Maximum Allowable Wellhead Operating Pressure (MAWOP), and generating a decision on whether the well is a workover candidate based on results of the comparison. The system includes a collecting tool that performs periodic surveys to monitor an annulus pressure of the well, determines the annulus pressure of the well over a period of time, and broadcasts information relating to the periodic surveys. The system further includes a processor that obtains the information relating the periodic surveys, compares the annulus pressure to a Maximum Allowable Wellhead Operating Pressure (MAWOP), and generates a decision on whether the well is a workover candidate based on the results of the comparison.

Methods for determining phase fractions of a downhole fluid via thermal properties of the fluids are provided. In one embodiment, a method includes measuring a temperature of a fluid flowing through a completion string downhole in a well and heating a resistive element of a thermal detector at a position along the completion string downhole in the well by applying power to the resistive element such that heat from the resistive element is transmitted to the fluid flowing by the position. The method also includes determining, via the thermal detector, a flow velocity of the fluid through the completion string and multiple thermal properties of the fluid, and using the determined flow velocity and the multiple thermal properties to determine phase fractions of the fluid. Additional systems, devices, and methods are also disclosed.

Methods for determining phase fractions of a downhole fluid via thermal properties of the fluids are provided. In one embodiment, a method includes measuring a temperature of a fluid flowing through a completion string downhole in a well and heating a resistive element of a thermal detector at a position along the completion string downhole in the well by applying power to the resistive element such that heat from the resistive element is transmitted to the fluid flowing by the position. The method also includes determining, via the thermal detector, a flow velocity of the fluid through the completion string and multiple thermal properties of the fluid, and using the determined flow velocity and the multiple thermal properties to determine phase fractions of the fluid. Additional systems, devices, and methods are also disclosed.

Multiphase flow metering is provided. In one possible implementation, a multiphase flow measurement system includes at least one reference temperature sensor at a first position configured to measure a first temperature of a multiphase flow. The multiphase flow measurement system also includes at least one heated temperature sensor at a second position downstream of the reference temperature sensor configured to excite the multiphase flow and measure a second temperature of the multiphase flow.