MDT Vs DST

[anihita]

Please throw some insight into the advantages , limitations and uses of MDT and DST.

[anihita]

DST : A brief overview:

Well tests conducted with the drillstring still in the hole. Often referred to as DST, these tests are usually conducted with a downhole shut-in tool that allows the well to be opened and closed at the bottom of the hole with a surface-actuated valve. One or more pressure gauges are customarily mounted into the DST tool and are read and interpreted after the test is completed. The tool includes a surface-actuated packer that can isolate the formation from the annulus between the drillstring and the casing, thereby forcing any produced fluids to enter only the drillstring. By closing in the well at the bottom, afterflow is minimized and analysis is simplified, especially for formations with low flow rates. The drillstring is sometimes filled with an inert gas, usually nitrogen, for these tests. With low-permeability formations, or where the production is mostly water and the formation pressure is too low to lift water to the surface, surface production may never be observed. In these cases, the volume of fluids produced into the drillstring is calculated and an analysis can be made without obtaining surface production. Occasionally, operators may wish to avoid surface production entirely for safety or environmental reasons, and produce only that amount that can be contained in the drillstring. This is accomplished by closing the surface valve when the bottomhole valve is opened. These tests are called closed-chamber tests. Drillstem tests are typically performed on exploration wells, and are often the key to determining whether a well has found a commercial hydrocarbon reservoir. The formation often is not cased prior to these tests, and the contents of the reservoir are frequently unknown at this point, so obtaining fluid samples is usually a major consideration. Also, pressure is at its highest point, and the reservoir fluids may contain hydrogen sulfide, so these tests can carry considerable risk for rig personnel. The most common test sequence consists of a short flow period, perhaps five or ten minutes, followed by a buildup period of about an hour that is used to determine initial reservoir pressure. This is followed by a flow period of 4 to 24 hours to establish stable flow to the surface, if possible, and followed by the final shut-in or buildup test that is used to determine permeability thickness and flow potential.

[DAH7542]

I came across with this summary comparing Formation Testing (such as MDT, RFT...) vs Well Testing (DST among others). I hope it helps.

[ngocquydoan]

Thank you for your explanation, it's so clear

[jackofalltrades]

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[nmnm123]

hi

it is very useful

thanks