A method is provided for determining the actual inflow rates of gas and liquid into a wellbore from a reservoir. The wellhead is first closed and the wellhead pressure is measured over time. For a briefly period, gas is flowed from the wellhead and the wellhead pressure is measured again. Using the two conditions, the original wellbore gas volume and an original fluid inflow rate is determined. Gas is again flowed from the wellhead, both the flow and the pressure being measured, but this time for a prolonged duration, sufficient to affect the reservoir. Assuming original gas inflow rate and original gas volume remain unchanged during the prolonged flow, a total rate of fluid inflow from the reservoir is determined, and finally an incremental inflow rate of fluid from the reservoir is calculated as being the difference between the total rate of fluid inflow less the original rate of gas flow. If the well is a gas well, the incremental fluid inflow is the actual gas inflow rate. If the fluid inflow is known to be liquid, then an incremental change in volume is equivalent to the liquid inflow rate. Using an exponential relationship for the pressure change during wellhead flow, a theoretical curve pressure response curve can be created, displayed and compared against the actual pressure response, any deviation therebetween being indicative of fluid inflow from the reservoir.

Method for determining the volume of fluid produced and other production characteristics from a subterranean formation during a drill stem test based on determining the location of well fluid within the drill stem tubing by measuring the travel time of an acoustic signal reflected from the well fluid.

A method is provided for determining the inflow rates of gas and liquid upon completion of an underbalanced well. The casing is placed, blocking fluid communication between the well and the formation. A tubing string is run in, forming an annular space and a tubing bore. The well is conditioned by removing sufficient liquids to create an underbalanced state and leaving a gas-filled space above any residual liquid. The volume of the gas-filled space in the annular space and the tubing bore is determined. The well is perforated, opening communication between the well and the formation. Pressure within the tubing bore and annulus is measured as a function of time. The rate of change of pressure is dependent upon the nature of the incoming fluid; be it gas or liquid. From the above, the rate of incoming fluid can be established as a function of the volume of the gas-filled space and the rate of change of pressure. The inflow rates of solely gas or solely liquid may be determined whether substantially all the liquid is removed during conditioning or only some of the liquid is removed.

A method and apparatus for determining the transmissibility of a fluid-conducting layer (stratum), such as an aquifer that is accessible through a borehole. The fluid-level in the borehole is stimulated to a periodic or an aperiodic damped oscillation. By measuring and reading the motion of the fluid-level and evaluating the motion, the transmissibility can be calculated.

The pressure build-up of hydrocarbon wells is quickly measured allowing the well to be shut-in for a shorter length of time than previously possible to achieve the same results. After the well has been shut-in at the surface the rate of change of the level of the gas/liquid interface within the well bore is determined. The level change data are converted into pressure build-up data and flow rate data. Applying the convolution integral to the pressure build-up data gives the value of the equilibrated pressure of the well. The deconvoluted data can then be used to solve conventional algorithms to determine the state of the well bore and surrounding formation. The operator of the well can then make a variety of decisions, including continuing to produce from the well, stimulating the well, or abandoning the well.