Flow Rate Behavior and Imbibition Comparison Between Bakken and Niobrara Formations

Wang, Dongmei; Zhang, Jin; Butler, Raymond; Clark, Adam; Rabun, Rachel; Koskella, Dave

doi:10.15530/urtec-2014-1920887

Cited by 16 publications

(9 citation statements)

References 17 publications

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“…Figure 4 shows results for four samples. Figure 5 from Wang et al (2014) shows typical imbibition rate data for Bakken and Niobrara shale samples retrieved from tight oil formations. We notice that imbibition behavior typically fits a power law function with negative exponential component indicating a reducing imbibition rate with time that is linear when plotted on log-log scale.…”

Section: Interactions Between Fluids Salt and Shalementioning

confidence: 99%

“…Imbibition studies on shale core samples have been done at atmospheric pressures with no confining stress (Akbarabadi and Piri, 2014;Morsy, Gomaa and Sheng, 2014;Wang et al, 2011;and Wang et al, 2014), and only in some cases (Wang et al, 2011;and Wang et al, 2014) at elevated temperatures.…”

Section: Interactions Between Fluids Salt and Shalementioning

confidence: 99%

“…Blauch et al (2009) observed that the water chemistry fingerprint of flowback water in Marcellus wells is similar to that of the brine in the Oriskany aquifer and concluded that produced water may be dissolving salt minerals in the shale and/or may be flowing directly from the aquifer. Wang et al (2014) report formation water salinities of between 150,000 to 300,000 mg/L in the Williston basin, North Dakota. Vazquez et al (2014) report that scale is deposited in the wellbores during flowback due to the liberation of salts from the formation by (in most cases slickwater) fracturing fluid.…”

Section: Increasing Flowback Fluid Salinitymentioning

confidence: 99%

“…This section will estimate the imbibition volume using the equations for imbibition rate obtained from data obtained by Roychaudhuri, Tsotsis, and Jessen (2011) and Wang et al (2014). Dividing Eq.4 by the fracture porosity presented in Eq.5, we obtain A sf in terms of fracture porosity f and x sf as (18) Using power functions for leakoff rate from laboratory studies,…”

Section: Imbibition and Trapped Fluid Volumementioning

confidence: 99%

“…In all cases, the volume of fluid available to imbibe can be considered infinite, where as in practice, the opposite is the case. Additionally, the experiments are conducted at surface conditions -in some cases (Wang et al, 2014) elevated temperature, but in all cases, without confining stress applied to the samples and not at reservoir pressure. Makhanov (2013) described the free gas flow into hydraulic fractures prior to production as counter current imbibition.…”

Section: Imbibition and Trapped Fluid Volumementioning

confidence: 99%

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Model for a Shale Gas Formation with Salt-Sealed Natural Fractures

Merry

Ehlig-Economides

Pang

2015

Day 3 Wed, September 30, 2015

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Most multiple transverse fracture horizontal wells in shale gas formations remain in transient bilinear or linear flow for very long periods, typically several years. Some plays show very different behavior that has been attributed to pressure dependent permeability. Often, there are reported cases of shale wells that exhibit boundary dominated flow in a very short period that implies a stimulated rock volume (SRV) much smaller than would be expected based on the hydraulic fracture treatment design. This paper offers an alternative explanation for the early boundary dominated flow related to dissolution of salt-sealed natural fractures in the shale. Three plays are the target of this study, namely, the Haynesville shale, the Marcellus shale, and the Horn River Basin.Flowback of water with significantly higher salinity than the injected fracture fluid may suggest that the injected low salinity fracturing fluid dissolved salts that seal an existing natural fracture system. Evidence would be seen in long-term transient rate and pressure production data as early boundary dominated flow providing the natural fracture pore volume dissolved by injected low salinity fracturing fluid that leaked off during the hydraulic fracture treatment. In this scenario, the effective permeability would represent that of the natural fracture system induced by salt dissolution, and the stimulated rock volume would be directly related to the leakoff volume.This study first discusses a plausible diagenetic history for generation of a salt-sealed natural fracture system in shale gas and how core, log, and conventional test data may behave. We then present a material balance model for behavior of the salt-sealed fracture porosity, the shale matrix porosity, and fracture pore volume dissolved by the leaked off fracture fluid, during the fracture treatment and subsequent early and long term production. We show the resulting permeability loss as residual water vaporizes. The significance of the model is a new rationale for a correlation between apparent stimulated rock volume and injected fluid during hydraulic fracturing.

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Section: Interactions Between Fluids Salt and Shalementioning

confidence: 99%

Section: Interactions Between Fluids Salt and Shalementioning

confidence: 99%

Section: Increasing Flowback Fluid Salinitymentioning

confidence: 99%

Section: Imbibition and Trapped Fluid Volumementioning

confidence: 99%

Section: Imbibition and Trapped Fluid Volumementioning

confidence: 99%

See 3 more Smart Citations

Model for a Shale Gas Formation with Salt-Sealed Natural Fractures

Merry

Ehlig-Economides

Pang

2015

Day 3 Wed, September 30, 2015

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Improving oil recovery of Eagle Ford shale samples using cryogenic and cyclic gas injection methods - An experimental study

Altawati

Emadi

Pathak

2021

Fuel

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Factors Affecting CO₂-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests

2017

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Shale oil reservoirs such as Bakken, Niobrara, and Eagle Ford have become the main target for oil and gas investors as conventional formations started to be depleted and diminished in number. These unconventional plays have a huge oil potential; however, the predicted primary oil recovery is still low as an average of 7.5%. Injecting carbon dioxide (CO 2 ) to enhance oil recovery in these poor-quality formations is still a debatable issue among investigators. In this study, three steps of research have been integrated to investigate the parameters that control the success of CO 2 huff-n-puff process in the field scale of shale oil reservoirs. First, a numerical simulation study was conducted to upscale the reported experimental studies outcomes to the field conditions. The second step was to validate these numerical models with the field data from some of CO 2 -EOR pilots, which were performed in Bakken formation, in North Dakota and Montana regions. Finally, statistical methods for Design of Experiments (DOE) have been used to rank the most important parameters affecting CO 2 -EOR performance in these unconventional reservoirs. The Design of Experiments approved that the intensity of natural fractures (the number of natural fractures per length unit in each direction, I-direction, J-direction, and K-direction) and the conductivity of oil pathways (the average conductivity for the entire oil molecules path, from its storage (matrix) to the wellbore) are the two main factors controlling CO 2 -EOR success in shale oil reservoirs. However, the fracture intensity has a positive effect on CO 2 -EOR, while the later has a negative effect. Furthermore, this study found that the porosity and the permeability of natural fractures in shale reservoirs are clearly changeable with the production time, which, in turn, led to a clear gap between CO 2 performances in the lab conditions versus what happened in the field pilots. This work reported that the molecular diffusion mechanism is the key mechanism for CO 2 to enhance oil recovery in shale oil reservoirs. However, the conditions of the candidate field and the production well criteria can enhance or downgrade this mechanism in the field scale. Accordingly, the operating parameters for managing CO 2 -EOR huff-n-puff process should be tuned according to the candidate reservoir and well conditions. Moreover, general guidelines have been provided from this work to perform successful CO 2 projects in these complex plays. Finally, this Article provides a thorough idea about how CO 2 performance is different between the field scale of shale oil reservoirs and the lab-scale conditions.

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Flow Rate Behavior and Imbibition Comparison Between Bakken and Niobrara Formations

Cited by 16 publications

References 17 publications

Model for a Shale Gas Formation with Salt-Sealed Natural Fractures

Model for a Shale Gas Formation with Salt-Sealed Natural Fractures

Improving oil recovery of Eagle Ford shale samples using cryogenic and cyclic gas injection methods - An experimental study

Factors Affecting CO₂-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests

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Flow Rate Behavior and Imbibition Comparison Between Bakken and Niobrara Formations

Cited by 16 publications

References 17 publications

Model for a Shale Gas Formation with Salt-Sealed Natural Fractures

Model for a Shale Gas Formation with Salt-Sealed Natural Fractures

Improving oil recovery of Eagle Ford shale samples using cryogenic and cyclic gas injection methods - An experimental study

Factors Affecting CO2-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests

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Product

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Factors Affecting CO₂-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests