Well Testing

What a tumultuous, challenging, and exciting year 2015 was. The roller-coaster ride made it a year ripe for mergers and acquisitions. Within the next few months, a few of the common company names in our industry will soon be part of history books, dwindle in our memories, and eventually disappear from our vernacular. Geopolitical unrest, unpredictable weather conditions in all parts of the globe, and distrust shook the world.

As is usually the case under these circumstances, panic spread like wildfire and layoffs became the norm. Recent university graduates were having difficulty landing well-remunerated jobs and were forced to move back in with their parents or find menial jobs until conditions improve. Some consulting firms talk about cautious optimism for 2016, not necessarily in regard to the oil price rebounding quickly. Nonetheless, despite the naysayers’ comments and predictions, the usual creativity and ingenuity of engineers and scientists in the oil industry were ubiquitous.

Downhole temperature measurements have been commonplace in production logging to allocate production when multiple reservoirs are produced commingled. Because of the success derived from distributed-temperature sensors and fiber-optic cables, the temperature history acquired during a well test is also receiving interest among practitioners. The downhole temperature history is a quasimirror-image of the downhole pressure and, thus, can be used to infer the behavior of fluids in the wellbore, as well as to assist in the interpretation during pressure transient analysis. Basically, engineers now have access to additional information in their toolbox that can be integrated into a comprehensive analysis of the field, within the volume surveyed during production. It is the integration of engineering, geological, and geophysical information that increases the value of the interpretation from a well test. In fields with complex reservoirs, this holistic approach is definitely adding value to the teams in charge of putting together a development program.

Despite a smaller volume of articles and presentations on well testing in 2015, relative to previous years, the articles chosen for this issue of JPT show the breadth of applications, as well as the ingenuity of experts and academics. As difficult as it is to narrow down the publications to three selections, I believe that, in the end, these three manuscripts show the incisive use of well-test data. Of course, the interested reader is encouraged to seek further articles on this topic in the OnePetro library.

Recommended Additional Reading

SPE 172689 The Evolution of Well-Testing Practices From Conventional to Zero Flaring in a Saudi Aramco Oilfield Development by L. Duthie, Saudi Aramco, et al.

SPE 174897 Testing a Heavy-Oil Well in Ultradeep Waters: Challenges Overcome by State-of-the-Art Technology in Atlanta Project, Santos Basin, Brazilby Carlos A. Pedroso, QGEP, et al.

SPE 175233 Successful DST Methodology Adopted in Highly Deviated, Deep, Sour, and High-Pressure/High-Temperature Exploratory Well: A Case Study by Abdulla Al-Ibrahim, Kuwait Oil Company, et al.


Angel G. Guzmán-Garcia, SPE, is an independent energy consultant. He holds a PhD degree in chemical engineering from Tulane University. Guzmán-Garcia spent more than 23 years with ExxonMobil, where he held a variety of positions: conducting research on the response of resistivity tools in shaly sands; investigating nuclear-magnetic-resonance petrophysical applications; conducting and interpreting production logging; designing fluid-sampling collection and pressure/volume/temperature analyses; and designing, executing, and interpreting well tests in both siliciclastic and carbonate environments. He is an instructor in well testing, production logging, and petrophysics and is a member of the JPT Editorial Committee.

Well Testing

Angel G. Guzmán-Garcia, SPE, Energy Consultant

15 January 2016

Volume: 68 | Issue: 2

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