Interpreting Step Rate Tests SRTs in Multi-Layered, Unconsolidated and Stress-Sensitive Formations

Ershaghi, Iraj; Ershaghi, Milad A.

doi:10.2118/190103-ms

Cited by 4 publications

(1 citation statement)

References 19 publications

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“…The step-rate test (SRT) is one of the most applicable methods to predict the transition from radial (matrix) to linear (fracture-dominated) flow. , Generally, plotting the stepwise increase of BHP versus the corresponding injection rates results in two lines with a distinctive breakpoint, the pressure of which is considered as the fracture-propagation pressure (see Figure ). , The declining slope of the second line shows the improved injectivity of reservoir and stems from the higher conducivity of induced fractures …”

Section: Co2 Injection Monitoring and Surveillancementioning

confidence: 99%

Well Injectivity during CO₂ Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects

et al. 2021

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Deep saline aquifers are among the most favorable geological sites for short-and long-term carbon geosequestration. Injection of CO 2 into aquifers causes various hydro-physical, chemical, and geomechanical interactions that affect the injectivity of wellbores. Despite the extensive research conducted on carbon capture and storage (CCS), there exists a lack of focus on the concept of injectivity. The present study aims to identify the gaps by reviewing the major factors contributing to CO 2 injectivity in deep saline aquifers. Moreover, the existing analytical and numerical mathematical models to estimate maximum sustainable injection pressure and pressure build-up are critically reviewed. Concerning the analytical models, the main controversies are related to the general shape of the CO 2 −brine interface that stems from neglecting or assuming CO 2 compressibility, mutual solubility of CO 2 and water, and drying-out effects. Besides, the models predicting waterflooding processes cannot accurately evaluate the injectivity of CO 2 due to the unique features of CO 2 . Furthermore, most models have concentrated on CO 2 storage capacity at the reservoir scale and not on wellbore injectivity. Thermo-poro-elastic effects influencing the in situ stresses and constraining the maximum sustainable injection pressures are also neglected in some cases. Despite the numerous numerical modeling workflows or tools, some mechanisms have not yet gained the desired attention, especially the chemical aspects of CO 2 -rich brine. Finally, while the field data demonstrate the applicability of CO 2 geosequestration in saline aquifers, regular wellbore injectivity monitoring and surveillance is deemed necessary.

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Section: Co2 Injection Monitoring and Surveillancementioning

confidence: 99%

Well Injectivity during CO₂ Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects

et al. 2021

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Empirical Evidence Demonstrating Injection Containment and Absence of Injection Fracturing, Wilmington Oil Field Case Study

Kellogg¹,

Mercier²

2019

SPE Western Regional Meeting

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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.

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Empirical Evidence Demonstrating Injection Containment and Absence of Injection-Induced Fracturing, Wilmington Oil Field Case Study

Kellogg¹,

Mercier²

2020

SPE Reservoir Evaluation &Amp; Engineering

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Summary Waterfloods in California operate under the US Environmental Protection Agency's Class II underground injection control 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 using a step rate test (SRT), but this method has been shown to be inappropriate for multilayered, unconsolidated sandstone reservoirs (Ershaghi and Ershaghi 2018), which are prevalent in Wilmington Field. To avoid the potential for misinterpretation of SRTs to imply fracturing in this context, in this paper we summarize the evidence demonstrating both the effective geologic containment of injected fluid in the hydrocarbon-bearing zones and the absence of injection-induced fracturing. 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 multirate injection tests with injection profile surveys. These results provide data supporting the noted challenges associated with MASP determination for multilayered, unconsolidated reservoirs. In this paper, we give operators and regulators working in these types of fields a framework for assessing both injection containment and injection-induced fracturing that account for the unique properties of these formations.

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Interpreting Step Rate Tests SRTs in Multi-Layered, Unconsolidated and Stress-Sensitive Formations

Cited by 4 publications

References 19 publications

Well Injectivity during CO₂ Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects

Well Injectivity during CO₂ Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects

Empirical Evidence Demonstrating Injection Containment and Absence of Injection Fracturing, Wilmington Oil Field Case Study

Empirical Evidence Demonstrating Injection Containment and Absence of Injection-Induced Fracturing, Wilmington Oil Field Case Study

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Interpreting Step Rate Tests SRTs in Multi-Layered, Unconsolidated and Stress-Sensitive Formations

Cited by 4 publications

References 19 publications

Well Injectivity during CO2 Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects

Well Injectivity during CO2 Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects

Empirical Evidence Demonstrating Injection Containment and Absence of Injection Fracturing, Wilmington Oil Field Case Study

Empirical Evidence Demonstrating Injection Containment and Absence of Injection-Induced Fracturing, Wilmington Oil Field Case Study

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Well Injectivity during CO₂ Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects

Well Injectivity during CO₂ Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects