The energy transition is in a continuous pursuit of innovative technology applications from all corners of the oil and gas industry. With the exponential growth of carbon capture and sequestration (CCS) projects, similar subsurface appraisal objectives remain. Derisking dynamic reservoir performance and characterizing storage pore space are key enablers for prospective CCS projects.
The mention of well testing often takes readers to a visualization of hydrocarbon disposition by a flare. Once a bright and vibrant spectacle of our industry’s exploration updates, the days of flaunting a chairman’s flow or banker’s burn are past. Waning application of well testing during our energy transition is a specious assumption, and it’s the optics that are transforming as the well testing discipline proves its value to long-term carbon storage projects.
Injecting CO2 into the subsurface is hardly a new concept; operators have been doing this for decades as part of enhanced oil recovery. However, the application of injecting CO2 is changing in response to operators’ environmental, social, and governance ambitions. While carbon storage concepts exist in many forms, anchoring a storage project requires pore space of adequate quantity and quality in proximity to a fixed source of emissions. Carbon storage projects also must manage additional risks such as sustained injectivity performance, geologic seal integrity, and plume migration, to name a few.
Enter well testing. Quantifying injection performance of supercritical fluids is crucial for optimizing wells to meet project needs while minimizing the number of required penetrations through a structural seal. Whether for a saline aquifer or a previously depleted field, pressure transient analysis enhances an understanding of the pore space intended for storage and the potential heterogeneities within. Furthermore, integrating well testing with other reservoir-description tools may be used to monitor migration of stored fluids.
With corporate and regulatory targets driving the unprecedented pace and scale of CCS opportunities, well testing is quickly reaffirming itself as a powerful tool in characterizing pore space essential to our lower-carbon goals.
This month’s papers highlight ongoing developments within the well testing discipline and important reminders about how to properly use dynamic data. The application of these well testing fundamentals to a nascent carbon storage market is still evolving.
This Month’s Technical Papers
Precision in Defining Diagnostic Plots Optimizes Well-Test Results
Surveillance Optimizes Development Plan for a Deepwater Reservoir
Three-Phase Well-Flow-Measurement and Well-Testing Unit Provides Accuracy, Agility
Recommended Additional Reading
SPE 208967 Rate-Pseudopressure Deconvolution Enhances Rate-Time Models Production History-Matches and Forecasts of Shale Gas Wells by L.M. Ruiz Maraggi, The University of Texas at Austin, et al.
URTeC 3705570 Analysis of Multiple Flow/Buildup Tests Including a 5-year Buildup: Case Study of an Australian Shale Gas Well by Christopher R. Clarkson, University of Calgary, et al.
OTC 31691 Challenges and Mitigation Strategies for High-Rate Gas Well Testing in High-Pressure/High-Temperature DST Operation by Jakpakorn Hemaprasertsuk, PTTEP, et al.
Jeffrey Gagnon, SPE, is a subject-matter expert of transient well testing at ExxonMobil. He and his team oversee ExxonMobil’s worldwide exploration and appraisal testing (including design and planning, onsite operations supervision, and data interpretation and integration) while supporting pressure transient analysis for producing assets. Gagnon has co-authored SPE manuscripts regarding reservoir characterization and simulation. He holds MS and ME degrees in petroleum engineering from Robert Gordon University and Texas A&M University, respectively, and an undergraduate degree in civil engineering from the University of New Hampshire. Gagnon is a member of the JPT Editorial Review Board and can be reached at jeffrey.gagnon@exxonmobil.com.