The effective user must be able to:. The tools referenced in Table 1 are each described in greater detail in separate articles. A dead weight sinker bar is necessary to overcome the force of the wellhead pressure acting on the cross-sectional area of the logging cable.
The weight shown is just enough to balance the force of the well pressure acting on the wireline. Additional weight above that which is indicated on the graph is needed to realize downward movement of the logging string. As the inclination angle of the wellbore increases, it becomes especially important to increase the sinker bar weight over the value specified by the vertical axis of the figure.
When an inclination angle requires unreasonably long sinker bars, roller centralizers are required. Typical slickline diameters are represented by the group of lines at the bottom of Fig. The low sinker-bar weight needed to carry out a slickline survey, even at high wellhead pressures, requires only a short lubricator.
As a result, slickline services are enjoying a rebirth. New versions of these tools contain sufficient downhole memory to record what is essentially a continuous log. The ends of the tool contact the bottom of the borehole, and its middle touches the top. With the following equation, the maximum tool length that can pass through a bend can be calculated. While Fig. The expression for L t involves the hole and tool diameters, as well as the inside radius of the bend. The inside radius can be expressed in terms of the angle of the bend, and the distance to bend through the specified angle see Fig.
Any 1. OD tool 7. If longer tools are required, then the tool string must be segmented with "knuckle" joints. The counter wheels on a production-logging unit measure the length of cable in the well to an accuracy of 5 out of 15, ft, provided that a great deal of back and forth travel yo-yoing is not required to work the tool string down the well. Better depth control is obtained by placing a casing collar locator CCL sub at the top of any production-logging tool string.
This sub generates a voltage spike as it moves past a change in metal thickness, particularly as it passes through the connection between joints of pipe.
The resulting record of collars is the source of depth control. Wells are perforated from a perforating depth control PDC log, a combination of a collar log and a cased-hole nuclear log such as a gamma ray log. The nuclear log is then depth correlated to a similar log run before the well was cased. This procedure ties the collar record into the depth scale on the openhole logs.
Accuracy in this latter depth scale is maintained by means of magnetic flags placed at precise intervals—customarily, ft intervals—along the openhole logging cable. The PDC log is a part of the file on a given well and provides the collar record that serves as the depth reference for subsequent production logging.
A short joint of casing called a "pup" joint is often placed in the casing string as a depth marker. Otherwise, normal variations in length are used to correlate collar records. Sometimes a radioactive collar that emits gamma rays is used as a marker for depth control. For flush-joint casing, collars are available that are strapped around the casing before it is run into the hole.
Occasionally, radioactive bullets are fired into the formation before casing the well. Because of friction near the pipe wall, absolute fluid velocity is not the same as the average velocity of fluid moving through the pipe. After applying correction factors, engineers convert the spinner velocity to an average velocity using computer modeling techniques, which present the fluid velocity profile across the pipe diameter.
Pressure is a versatile measurement with several applications for reservoir and production engineers. Strain, sapphire and quartz gauges are the main devices used to measure pressure. Engineers may also measure pressure using a manometer —a device that converts mechanical displacement to pressure. From wellbore pressure data, engineers can determine well stability at the time of logging, estimate reservoir pressure from multirate logging surveys, calculate fluid density and obtain key reservoir parameters by performing transient rate analyses.
Temperature is an integral measurement for all production logging. Engineers use temperature data to make qualitative conclusions about fluid entries, particularly in low-flow rate scenarios in which a spinner may not be sensitive enough to detect movement.
Gas entries create cooling anomalies that are easily detected using temperature logs. Temperature measurements are also used in fracture treatment evaluation and to evaluate injection well performance. Using temperature data, engineers may be able to evaluate the integrity of well completions, detect casing leaks and identify flow through channels behind pipe.
Resistance temperature detectors, the most common type of sensor, usually consist of a platinum wire or film deposited on a nonconductive surface. Changes in temperature cause variations in resistance, which is calibrated and converted to temperature. Fluid density measurements differentiate oil, gas and water. Service companies have developed tools based on a variety of physical principles to obtain fluid density measurements:. In the case of two-phase flow, engineers can use fluid density—in conjunction with other measurements such as fluid viscosity—to compute holdup.
Where multiphase flow is present, they must employ tools with probes distributed across a wellbore to directly measure the fluid holdup. One type of tool senses differences in optical reflectance to obtain holdup, which involves measuring the amount of light reflected back from a fluid. Another type of tool differentiates water from oil and gas using probes that measure electrical properties of the fluids.
Auxiliary measurements commonly acquired by production logging strings are casing collar logs, gamma ray logs, caliper and deviation.
Casing collar and gamma ray logs provide depth control and correlation with completion components. Caliper and deviation data are used in production modeling programs. Production logs can be difficult to interpret because fluid flow may not be uniform, and multiple passes result in large amounts of data, some of which may produce conflicting answers.
Computer programs have been developed to assist engineers in understanding downhole conditions; computer-generated interpretations remove some of the ambiguities associated with the interpretation process below. The interpretation product can often help the engineer identify more-productive intervals, detect water entry and determine intervals that do not contribute to production.
To analyze production logging data, production engineers must be aware of downhole flow regimes. Knowledge of expected flow regimes allows opera-tors to choose measurements suitable for the downhole conditions.
Single-phase flow —when only oil, gas or water is produced—is the simplest flow to evaluate; however, it is uncommon in most wells. Share This. Don't have an account?
Click below to get started. Production Logging. Horizontal Well. Temperature Modeling. Formation Evaluation. DFO Monitoring. Data Extraction.
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