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Analysis Quality Determines Value of Diagnostic Fracture Injection Tests

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Diagnostic fracture injection tests (DFITs) incur direct and indirect costs resulting from the tests themselves and the extended time required for the pressure falloff, which delays the completion of the well. The benefits, therefore, must outweigh the costs if the test is to be justified. These tests are performed regularly around the world because a DFIT is one of only a few processes that can help quantify both geomechanical properties and reservoir-performance drivers within the same test.

Introduction

Operators and service providers commonly experience problems with DFIT execution and analysis despite efforts to reduce errors and inconsistencies. Before any field execution or analysis, the objectives of a DFIT must be considered. Historically, DFITs were performed predominantly for the purpose of designing better full-scale hydraulic-fracture treatments with early-time measurements of initial shut-in pressure, leakoff coefficient, and fracture closure having priority over reservoir parameters such as permeability and pore pressure. Increasingly, practitioners are using DFITs to measure reservoir parameters such as initial pressure and permeability. While, in many cases, these parameters may be obtained from a single successful test, other situations have time constraints or rock and reservoir properties that constrain operations to a point where priorities must be set. While leakoff and closure values are determined early in the DFIT shut-in period, reservoir pressure and permeability are derived from late-time measurements that may require longer falloff times.

The complete paper presents cases encountered in which test procedures/operations or incorrect analysis misled engineers. Cases presented are

  • Several Canadian Duvernay shale wells illustrating the importance of multiple tests and the use of gradients to understand fracture orientation and possible complexity.
  • A well where the initial DFIT had an injection rate that was too low combined with operational issues. A second test on the same interval yielded better results.
  • A Canadian Montney well where rock/fluid interactions led to a false radial-flow signature.
  • Two subnormally pressured Canadian oil wells where surface falloff pressure dropped to a vacuum (i.e., falling liquid level), causing late-time effects that were not reservoir related. The authors present a work flow to determine reservoir pressure in this situation.
  • An Australian naturally fractured gas well showing the importance of sufficient falloff time.

A proper DFIT may be critical for assessing the geomechanical and reservoir properties of unconventional reservoirs. However, simple guidelines such as wellbore conditioning, the understanding of pressure anomalies resulting from wells going on vacuum, and the importance of flow-regime identification are often overlooked, leading to poor results. Having access to numerous high-quality data sets from various international oil and gas operators provides insight to establishing some useful guidelines that are applicable anywhere in the world.

Discussion of job execution and pressure analysis will aid engineers who may not have access to DFIT methods and best practices. Topics addressed in the complete paper include test objectives and expected outcomes, the importance of supplementary data in conjunction with the test, the benefit of redundancy on the critical parameter of pore pressure, and test-design attributes such as surface pressure data vs. subsurface pressure using downhole shut-in tools.

The Whole Is More Than the Sum of Its Parts

Because all well tests, including DFITs, are executed and analyzed imperfectly despite best efforts to reduce errors and inconsistencies, the best defense against inclusive or erroneous conclusions is repetition. More data, or data collected redundantly, reduce the chance of missed opportunities to collect reservoir and fracture-stimulation data from a single misrun test. Even with success, multiple tests provide much more understanding than a single test. A single DFIT may not clearly show certain fracture behavior, but a family of tests may illuminate subtle, yet critically important, information.

Guidelines

Application. Why Perform a DFIT? DFITs have application in the appraisal setting to derisk major capital decisions that require independent verification of reservoir parameters.

Who Should Analyze? DFIT analysis should be conducted by those with an understanding of both hydraulic fracturing and reservoir engineering. Merging understanding of reservoir engineering and fracturing is necessary for robust analysis.

Design. How Much Interval Should Be Tested? DFIT analysis is preferred in a single, concise lithological interval to reduce uncertainty in the test height and the risk of communicating into multiple intervals with significantly differing geomechanical or reservoir properties.

What Is an Appropriate Job Size? DFIT injection rate and fluid volume should be sufficient to achieve fracture-height growth over a considerable portion of the test interval but not so great as to promote substantial out-of-zone height growth or excessive fracture length; the latter will extend the duration of flow periods and required shut-in time.

How Long a Wait Is Necessary? Wait time depends on test objectives. Identification of fracture closure normally is achievable within several hours. Reservoir flow periods for determining reservoir pressure and transmissibility may take many days or even weeks to develop. Modeling of DFIT fracture propagation and various test-design scenarios is recommended to provide necessary guidance.

Repeat, Repeat. If possible, plan multiple redundant tests in a new field to benefit from the idea that the whole is greater than the sum of its parts.

Execution. Bottomhole or Surface Data? Surface-acquired data are suitable when reservoir pressure is equal to or greater than the wellbore hydrostatic pressure. If reservoir pressure may be lower than wellbore hydrostatic pressure, consideration should be given to using downhole gauges and shutting in the well downhole upon termination of DFIT injection.

More About Surface. If surface pressure is used, the density of the wellbore fluid should be measured immediately before or during injection into the well or determined afterward with a slickline- or wireline-conveyed static-wellbore-pressure survey. To prevent inaccuracy caused by thermal-expansion effects, delay the DFIT for at least 24 hours after filling the wellbore with fluid and insulate the wellhead to minimize the effect of fluctuations in ambient temperature.

Gauges With Benefits. Bottomhole-pressure gauges can be preinstalled to estimate reservoir pressure from static conditions in cases with sufficiently high permeability. This can assist with the uniqueness of the analysis.

Not All Gauges Are Created Equal. Whether at surface or downhole, use of high-resolution, temperature-compensated gauges that have been recently calibrated (with documentation to verify this) is essential. Otherwise, the well-pressure falloff response may be unreliable or uninterpretable.

We’re Live! Live data transmission to the analyst is preferred to ensure that sufficient data are acquired.

Problems? Typical execution issues, such as air trapped in the wellbore and wellhead leaks, all have remedies, which are listed in Appendix A of the complete paper.

Interpretation. How To Function. Analysis requires a suitable time function to be used. For the purposes of after-closure analysis, various approaches can be followed.

Beware of False Signals. Distinguishing actual radial-flow pressure behavior from false lookalikes is important. The fundamental premise of after-closure analysis is that, ultimately, the injected fluid remains stationary and that the decline is affected only by the mobile reservoir fluid. This is a major assumption and may not always be true, however.

Know the Fractures. Natural fractures can affect the analysis. Know if the reservoir has them and consider their effect on the analysis.

Know the Gradients. Know the pressure gradients for each flow regime ­identified. Gradients are essential to understanding in-situ stress setting (e.g., normal, strike/slip, thrust fault) and will help identify when multiple plane fractures may be present, a possibility in many settings.

After-Action Review. The best way to gain confidence in DFIT analysis is to close the loop and review results, determining if the analysis is consistent with actual well productivity. When this is performed, a strong correlation is often found to exist.

For a limited time, the complete paper SPE 191458 is free to SPE members.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191458, “Good Tests Cost Money, Bad Tests Cost More: A Critical Review of DFIT and Analysis Gone Wrong,” by R.V. Hawkes, SPE, Trican Well Service; R. Bachman, SPE, CGG; K. Nicholson, Perpetual Energy; D.D. Cramer, SPE, ConocoPhillips; and S.T. Chipperfield, SPE, Santos, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed.

Analysis Quality Determines Value of Diagnostic Fracture Injection Tests

01 February 2019

Volume: 71 | Issue: 2

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