Sunday, July 30, 2017

Well Testing Design and Analysis chapter 1

In its simplest form, testing provides short-term production of reservoir fluids to the surface permitting the operator to confirm the show-indicated by cuttings, cores and logs- and estimate reservoir deliverability. In its subtlest form, measured pressure transients caused by abrupt changes in production can characterize completion damage, reservoir permeability and distant reservoir heterogeneities.

Primary concerns in testing exploration wells are obtaining representatives samples and estimating reservoir producibility. Fluid samples are needed to determine various physical parameters required for well test analysis, such as compressibility and viscosity, and for pressure-volume-temperature (PVT) analysis that unlocks how the hydrocarbon phases coexist at different pressures and temperatures.


For oil, a critical PVT parameter is bubblepoint pressure, the pressure above which oil is undersaturated in gas and below which gas within oil stars being released. Maintaining reservoir pressure above bubblepoint is key to successful testing since the principle of transient analysis, described below, holds only if flow in the reservoir remains monophasic. Estimating reservoir producibility requires achieving stable flow rates at several choke sizes and then determining the productivity index from the slope of the flow versus drawdown pressure data.


If well productivity is less than expected, the wellbore damage may be the cause. This is the next concern in testing exploration wells. Estimating the near-well-bore condition to perform necessary remedial action and ultimately to plan a well completion strategy for the field is accomplished from the transient analysis part of a well test.


Transient analysis, however, reaches deeper than just the near-wellbore region. Today, it contributes so much to characterizing the reservoir that engineers increasingly refer to well testing as reservoir testing. Analysis can indicate the likely producing mechanism of the formation-for example, how much production comes from fractures,, how much from intergranular porosity -and it can determine the producing zone's permeability-thickness product, kh. It can see to the limits of the reservoir indicating the probable shape (but not orientation) of the reservoir boundaries and can show whether the primary recovery mechanism is from water or gas-cap support. This information becomes crucial in the appraisal and production stages of field development when engineers combine testing interpretation results with seismic and geologic data to refine their understanding of the reservoir.




Drawdown pressure measurements to track these events practically mirror the buildup response. In fact, transients can be obtained simply by increasing or decreasing the flow rate.






The primary target is the near-wellbore region (picture above). The goal is to assess formation damage and , if necessary, perform stimulation. Test last just an hour or two. In a conventional test conducted to investigate reservoir boundaries, often called a limit test, the transient must be long enough for the pressure disturbance to reach the boundaries and then create a measurable response in the well. How long this takes depends on formation and fluid characteristics. In particular, the lower the formation permeability, the more time is needed-test can continue for days. Longest lasting are interference tests, in which the effect of a transient created in one well is observed in another, yielding information about reservoir transmissivity and storativity. 

The basic data obtained are change in pressure, delta p, versus elapsed time since the transient was initiated, delta t. 




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