Does formation-damage coreflooding give a good representation of damage that occurs downhole? For those of us who are actively involved in coreflooding, this is a common question to be asked. In addition, it is central with regard to the design of corefloods that will provide information enabling the qualification of specific drilling and completion fluids or identification of damage mechanisms for wells in production. Key to all of this is the selection of representative core material from the main production or injection intervals.
Formation damage represents a near-wellbore reduction in permeability during drilling, completion, or production, and the plugs selected for testing represent a point around the wellbore in which we attempt to identify either the damage mechanisms that can be expected for new wells or that may have occurred for wells in production. In order to achieve this, return-permeability tests are performed that are designed to replicate drilling and completion of wells, cleanup, and production. Each company has its own coreflood procedure, but they follow a basic pattern of a baseline permeability followed by application of mud and completion fluid. A cleanup sequence is performed, increasing either drawdown or flowrate, after which the plug can be spun down in an ultracentrifuge to irreducible brine saturation and a final permeability is measured that can be compared to the baseline permeability. The percentage difference between these permeabilities gives the return permeability.
At a recent meeting of those interested in formation damage from North Sea operators, I asked the question, “What is return permeability?” Is the most representative return permeability that identified after the cleanup sequence of the coreflood or that identified after spin down? With regard to the latter, one of my formation-damage colleagues often says that we cannot spin down the reservoir. Therefore, how representative is this permeability?
Another question asked at the same meeting was, “What are the pass/fail criteria for a formation-damage test?” Each company tends to have its own specific criteria, but one criterion commonly used is that a 60% return permeability is acceptable. However, this in itself is an oversimplification because a high-permeability reservoir (e.g., 10 darcy) could experience significant formation/completion damage without affecting well productivity. Furthermore, it does not take into account that openhole completions tend to be more resilient to damage because of the high surface area available for inflow.
After we have performed our coreflooding, obtained return permeabilities, and identified the formation-damage mechanisms for the different tests performed, a common question asked is, “How do these values relate to potential well productivity?” This is a fundamental question and one for which we have not had an adequate answer. Recently, however, computational fluid dynamics has been used with some success to relate coreflood data to provide an indication of production rates. Predicted values have been shown to be similar to actual production rates achieved.
I hope you enjoy the papers.
This Month's Technical Papers
Recommended Additional Reading
SPE 174174 Integrated Approach To Managing Formation Damage in Waterflooding by Sergey Aristov, Shell, et al.
SPE 174188 Bursting the Skin Bubble—Decoupling Formation Damage From Skin in Complex Well Geometries by Michael Byrne, LR Senergy, et al.
SPE 174199 New Laboratory Method To Assess Formation Damage in Geothermal Wells by Zhenjiang You, The University of Adelaide, et al.
Niall Fleming, SPE, Leading Adviser, Statoil
01 February 2016
Diagnostic Tool Identifies Factors in Well-Productivity Decline
Wells in deepwater reservoirs show significant rate decline with time as the result of various causes. A diagnostic tool for quantification of factors influencing well-productivity decline is presented in this paper.
One of the frustrating aspects of well-productivity analysis is identifying the causes of lower-than-expected production/injection during initial well lifetime. Our task is to evaluate the multivariate aspects of well design.
Test Methodology Optimizes Selection of Fluids for Gasfield Development
For the development of the Dvalin high-pressure/high-temperature (HP/HT) gas field in the Norwegian Sea, a completion scheme using standalone screens is planned.
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26 May 2020
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