Detecting subsurface fluid leaks in real-time using injection and production rates

Singh, Harpreet; Huerta, Nicolas

doi:10.1016/j.advwatres.2017.10.012

Cited by 10 publications

(3 citation statements)

References 41 publications

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“…The imbibition and retention of fracturing water play a key role in shale gas transport and production. − Generally, the retention and low recovery of fracturing water are assumed to restrict the productivity of the gas wells, because of the low relative permeabilities to both gas and water in the two-phase region. − Marcellus shales were reported to lose 90–99% of the gas permeability after countercurrent spontaneous imbibition of water . This severe decrease in gas permeability was thought to be related to water block during spontaneous imbibition and would be detrimental to the deliverability of shale formations.…”

Section: Introductionmentioning

confidence: 99%

Modeling Water Imbibition and Penetration in Shales: New Insights into the Retention of Fracturing Fluids

et al. 2021

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Understanding the penetration and retention of fracturing water in geological systems is important for hydrocarbon extraction and fluid disposal during hydraulic fracturing. This paper explores the imbibition of fracturing water and its penetration profiles on shales from Sichuan Basin, China. Water imbibition experiments were performed on the collected shales with a variety of mineralogical compositions and pore structure characteristics. Sorptivity, quantitatively characterizing water imbibition capacity, was evaluated and its dependence on rock fabric and mineralogical compositions was examined. Then, a nonlinear diffusion model is presented to simulate the capillary flow during the water imbibition process according to the unsaturated flow theory. The solution of this model offers quantitative information about water penetration and distribution in shales. The water sorptivity of shales ranges from 0.1 to 1.8 × 10–6 m/s0.5. Water imbibed by shales is mainly along the shale lamination and bedding. The strong mineral alignment also contributes to sorptivity because of the preferential transport pathways. Shales with developed microfracture networks have higher sorptivity. Nevertheless, water penetration into shales is commonly less than 5 cm during the typical shut-in period after fracturing operations. The fracturing fluid loss is related to the development of microfracture networks and the fracture width. The complex fracture networks with a small fracture width result in low water recovery.

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Section: Introductionmentioning

confidence: 99%

Modeling Water Imbibition and Penetration in Shales: New Insights into the Retention of Fracturing Fluids

et al. 2021

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“…Also, with today's transducers technology, pressure can be measured with high resolution and accuracy at subsecond frequencies. The pressure in the injection zone has been shown to be useful to obtain information on fluid migration from the injection zone 37–39 . More studies investigated the pressure transient in the overlying zone hosting the migrated fluids.…”

Section: Introductionmentioning

confidence: 99%

Cross‐well pressure test analysis for CO₂ plume characterization based on arrival time and peak pressure change observations

Zeidouni

2021

Greenhouse Gases

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CO2 migration from the injection zone into an upper zone is possible through potential migration paths such as improperly abandoned wells or other weaknesses in the caprock overlying the injection zone. Various monitoring technologies may be used to obtain information on the resulting CO2 plume in an overlying zone. Cross‐well pressure testing—where water is to be injected/produced at a well and the pressure response to be observed at monitoring well(s)—has been previously investigated to characterize the CO2 plume. However, the methods proposed in the literature are not simple and may be computationally expensive either in forward modeling, inverse modeling, or both. For the cross‐well test analysis proposed herein, both the forward solution—a closed‐form analytical model—and the inverse model—a well‐posed overdetermined system of nonlinear equations—are simple. Consequently, a simple analysis methodology is presented to invert the cross‐well test data to obtain important information on the plume. To achieve this simplified approach, the migrated CO2 plume is assumed circular in shape with constant gaseous CO2 fraction over the plume area. The analysis methodology is first validated using a single‐phase model with a circular heterogeneity. Next, the methodology is applied to synthetic cross‐well pressure test data for a two‐phase system with CO2 plume. The arrival times and peak pressure change values from multiple monitoring wells are used to estimate the location and size of the plume. The estimated values are in good agreement with the actual plume size and locations used in generating the synthetic data. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd.

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“…6 The importance of safe and effective long-term storage of CO 2 requires that the behavior of geologic storage sites can be predicted sufficiently accurately and that the geologic storage systems perform in conformance with expectations and engineering tolerances. In this regard, the focus of past studies has been to understand the behavior of these systems, including migration within the storage reservoir, [7][8][9] chemical reaction with geologic media, 10,11 potential leakage through wells, [12][13][14][15][16] leak through the caprock, [17][18][19][20] potential leakage through faults and fractures, 19,21,22 and impact of variable injection schemes. 23 Some studies have also considered the impact of these phenomena as a function of scale [24][25][26][27][28] and various multiphase modeling approaches for CO 2 storage.…”

Section: Introductionmentioning

confidence: 99%

Two risk metrics for CO₂storage reservoirs with varying domain size, heterogeneity, and injection rate

Singh

Bromhal

2019

Greenhouse Gases

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Two parameters that play the most important role in the appraisal of environmental risk performance at carbon dioxide (CO2) storage sites are the prospective impact of the pore pressure increase and CO2 saturation. In this context, this study investigates the spatiotemporal evolution of pressure buildup and CO2 saturation as a function of flow region's size, average porosity and permeability, and heterogeneity, as well as the injection rate and total volume of injected fluid. The practical importance of this study is to investigate the factors that affect the extent of pressure buildup and areal extent of CO2 plume both during and after injection, which will impact risk assessment as well as influence effective monitoring operations. This study pursues the above objective using two risk metrics that are based on numerical simulations and illustrated using representative models of three realistic storage sites with varying volumetric storage potential and geological settings, all with open geologic systems. The two metrics (the spatiotemporal extent of pressure buildup and CO2 saturation plume, respectively) used in this study are able to capture the geologic (structural and petrophysical) and operational complexities that cannot be incorporated into analytical or semianalytical solutions. The results of this study suggest that in addition to the average permeability, the areal extent of the pressure buildup during the injection period is strongly related to the injection rate, whereas the postinjection period may be more strongly influenced by the reservoir heterogeneity. The areal extent of the saturation plume during active injection is highly correlated to the mass of injected fluid, and the postinjection behavior is impacted by the shape of the reservoir–seal interface. These findings are consistent with other recent studies by the National Risk Assessment Partnership (NRAP) on characteristic reservoir behavior. The results have been used to generate pressure and saturation plume profiles (over time) that can be used to support risk‐based decision making. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

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Detecting subsurface fluid leaks in real-time using injection and production rates

Cited by 10 publications

References 41 publications

Modeling Water Imbibition and Penetration in Shales: New Insights into the Retention of Fracturing Fluids

Modeling Water Imbibition and Penetration in Shales: New Insights into the Retention of Fracturing Fluids

Cross‐well pressure test analysis for CO₂ plume characterization based on arrival time and peak pressure change observations

Two risk metrics for CO₂storage reservoirs with varying domain size, heterogeneity, and injection rate

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Detecting subsurface fluid leaks in real-time using injection and production rates

Cited by 10 publications

References 41 publications

Modeling Water Imbibition and Penetration in Shales: New Insights into the Retention of Fracturing Fluids

Modeling Water Imbibition and Penetration in Shales: New Insights into the Retention of Fracturing Fluids

Cross‐well pressure test analysis for CO2 plume characterization based on arrival time and peak pressure change observations

Two risk metrics for CO2storage reservoirs with varying domain size, heterogeneity, and injection rate

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Cross‐well pressure test analysis for CO₂ plume characterization based on arrival time and peak pressure change observations

Two risk metrics for CO₂storage reservoirs with varying domain size, heterogeneity, and injection rate