It is a common practice to test a newly drilled well. Some companies prefer doing drillstem test (DST) down the wellbore since the results are more thoroughly and the radius of investigation is farther away. The produced fluid (oil, gas and water sample) can be checked to ensure the well has been cleaned to begin the well flow test. The fluid samples can be collected on surface for further analysis in the lab such as the procedure for oil, gas, water testing. However, the DST is expensive and requires extensive production testing equipment and safety precaution. Many well testing companies could provide the services to install and run the integrated drillstem test.
The newly drilled well also can be tested by using a closed chamber test (CCT) apparatus or wireline tools tester. Both have shallow investigation radius and most likely are influenced by mud filtrates. There is no flow to surface on both method thereby no extensive production testing equipment. CCT is an efficient form of conventional drillstem test since the CCT equipment, P/T gauges, and perforating gun are installed on the bottom of the string, and pressure buildup test is directly executed after perforating gun is fired.
A development well is tested to asses near wellbore damage or skin factor. Even skin factor is not directly measurable, it can show the level of damage around the wellbore. In a development well, near wellbore damage might be due to incompatible well service fluid, fine migration, turbulence flow, scaling, clay swelling, and particle plugging. Some damage can be overcome by just flowing the well others need analysis of formation transmissibility, decline rate, remaining reserves, capillary pressure and wettability.
Various models are available to interpret well test measurement and produce skin factor. The model can be for homogenous reservoirs or dual-porosity reservoirs or hydraulically fractured reservoirs. The well test data must be run on all models available and chosen the best match. One popular model is history matching by using the pressure derivative. Conventionally, those models produce only one skin factor.
Actually, the skin factor continuously decreases during production due to the continuous reduction of mud filtrate (Figure 1). In a good perforation and clean-up, the initial and end skin factor are small (line 4 on the picture) but in a bad perforation and clean-up, the initial and end skin factor are big.
In this current invention by well testing companies, the apparatus (CCT) and method to analyze the measurements are integrated. The closed chamber test apparatus (Figure 2) has improvement. The apparatus eliminates complicated wellbore dynamics due to surge flow by closing the chamber at optimal time. The optimal time is determined through the analysis of bottom hole pressure (BHP). The testing can be repeated several times until measurements are satisfactory. A circulating valve is used to empty the chamber by using Nitrogen as a pusher.
A retrievable packer is set as close as possible to the reservoirs being tested to eliminate long wellbore fluid loading. After firing the perforating gun, the reservoirs fluid will flow through the perforation toward the fluid inlet. The bottom hole pressure gauge (BH pressure gauge) will record the pressure and being monitored on the surface. The fluid will flow continuously to the closed chamber through the bottom valve. The bottom valve will be closed before opening the fluid sampler along with recording the pressure and temperature of sampling. The closed chamber can be purged by Nitrogen to empty the chamber and circulate the fluid through a circulating valve.
The measured pressures are analyzed by using multi models and functions, analytically and numerically such as pressure buildup test analysis. Reservoir pressure is calculated if not available through measurement. The flow rate can be measured or calculated. The model with the best match is chosen to determine reservoir properties and skin factor.
Recommended reading and capillary pressure demonstrator: