Tuesday, August 1, 2017

The Nuts and Bolts of Well Testing

Well testing is a dynamic process. At its simplest, a test discovers if a formation can flow and permits sampling of the produced fluid. Analysis can yield further information like the extent of formation damage near the borehole, reservoir permeability and heterogeneity, and initial productivity index. For this , engineers induce pressure transients by changing the rate that formation fluids enter the borehole and recording the resulting downhole pressure versus time. Transient tests can also reveal the reservoir's areal extent and vertical layering. 

Testing hardware has to perform a range of tasks. First, the formation being tested must flow. If the well has not already been completed, it needs to be temporarily completed-that is, to have a packer set above the test zone to isolate it from the wellbore fluid's hydrostatic pressure. 

To induce pressure transients, the engineer needs to control the well. The easiest method is surface shut-in. But during pressure buildup, the column of fluid between the point of shut-in and the formation has to be compressed by inflowing formation fluid-the so called wellbore storage effect. Data analysis usually requires that pressure be recorded until wellbore storage no longer dominates. 

When the wellbore volume is large (as in deep or horizontal wells) or the wellbore fluids highly compressible (as in gas wells), the wellbore storage effect cant last a prohibitevely long time. One way to minimize wellbore storage places a test valve downhole, as close as possible to the formation. Pressure gauges must be located below this test valve. 

Data gathering is not an exclusively downhole activity. On surface, after the fluid has been controlled and separated, flow rate can be measured. Taking a sample of the produced fluid is also important. Detailed analysis of samples not only sheds light on the composition of the produced fluid but also offers insight into the reservoir itself. The dynamic performace of a reservoir is both a function of the formation and the formation fluid. 

Openhole Testing- The first tests were conducted in open hole with the tools conveyed into the well on drillpipe-openhole drillstem test (DSTs). while the earliest DST hardware back to Johnston tools of the 1920s, the modern era of testing really started in 1950s. Then, multiflow evaluation tools were introduced, making possible repeated flow and shut-in cycles rather than the single flow and buildup offered before.

Today, multiflow evaluation tools are still used in the majority of openhole DSTs. If hdyrocarbons are detected in either cores or cuttings during drilling or indicated by logs, a DST may be used to rapidly assess the production potential of the formation. Drilling information or a wireline caliper log are used to locate a suitable packer seat- a section of openhole that is in gauge and looks capable of facilitating a good seal. The test string is designed so that the packer is opposite its seat when the perforated anchor is at the bottom of the well. 

The packer is traditionally a solid unit of rubber that expands when some of the weight of the string is set down onto the anchor. The test valve is also opened and closed by setting down and picking up on the string. Therefore, to ensure that pipe manipulation does not unset the packer, a tool above it hydraulically maintains the downward force. The packer can be unset only by an extended pull for several minutes. After the test has been completed and the test string pulled out of hole, drilling continues and the process can be repeated on subsequent hydrocarbon shows. 

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