Empirical Evidence Demonstrating Injection Containment and Absence of Injection Fracturing, Wilmington Oil Field Case Study
- Ryan P. Kellogg (California Resources Corporation) | David J. Mercier (California Resources Corporation)
- Document ID
- Society of Petroleum Engineers
- SPE Western Regional Meeting, 23-26 April, San Jose, California, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. Society of Petroleum Engineers
- 5.6 Formation Evaluation & Management, 0.2 Wellbore Design, 0.2.2 Geomechanics, 5.4.1 Waterflooding, 5 Reservoir Desciption & Dynamics, 3 Production and Well Operations, 5.6.1 Open hole/cased hole log analysis, 5.4 Improved and Enhanced Recovery, 3 Production and Well Operations
- step rate test, waterflood injection, injection gradient
- 1 in the last 30 days
- 92 since 2007
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Waterfloods in California operate under the EPA's Class II Underground Injection Control ("UIC") regulations, which are tasked with the protection of Underground Sources of Drinking Water ("USDW") within the state. A key aspect of this regulatory framework is the operation of water injection wells under a maximum allowable surface pressure ("MASP") to ensure that injected water does not induce and/or extend formation fractures that could create a potential conduit connecting the hydrocarbon zone with identified USDWs. Determination of the MASP for individual injection wells has typically been calculated via Step Rate Test ("SRT"), but this method has been shown to be inappropriate for multilayered, unconsolidated sandstone reservoirs (Ershaghi, 2018) which are prevalent in the Wilmington Field. To avoid the potential for misinterpretation of SRTs to imply fracturing in this context, this paper summarizes the evidence demonstrating both the absence of injection-induced fracturing and effective geologic containment of injected fluid in the hydrocarbon bearing zones.
This paper employs multiple sources of operational data derived from 50+ years of waterflooding that demonstrate injection containment without pressure induced waterflood fracturing at the Wilmington Field. In this study, we use over 18,000 injection profile surveys, 3000+ well logs, and targeted 3D modeling to examine in-zone injection water containment. To examine the evidence supporting injection in the absence of fracturing conditions, we evaluate field data from 500+ injectors using industry accepted diagnostic plots (e.g. injectivity index, Hall+Hall derivative, pressure falloff tests). In addition, a series of field tests were conducted to assess the stress sensitivity of the Wilmington reservoirs and investigate in-situ changes in the reservoir at higher injection pressures by combining multi-rate injection tests with injection profile surveys.
Using this data, we establish that Wilmington waterflood operations under current injection gradients demonstrate both in-zone containment and no evidence of fracturing. Building upon observations from over 50 years ago (Allen, 1968), we show that the multilayered, unconsolidated nature of the largest reservoirs in Wilmington can result in potential misinterpretation of SRTs to imply fracturing where none occurs. In response, we offer alternative explanations for observed pressure-rate trends when interpreting these tests. Depending on the reservoir's geomechanical and in-situ properties, we recommend alternative testing tools when establishing MASP in multilayered, unconsolidated sands.
These results provide extensive field data supporting the noted challenges associated with injection gradient determination for multilayered, unconsolidated reservoirs. This paper gives operators and regulators working in these types of fields a framework for assessing both injection containment and injection-induced fracturing that takes into account the unique properties of these formations.
|File Size||2 MB||Number of Pages||26|
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