Fundamentals of Shale Stabilization: Water Transport Through Shales

Ballard, Tracey; Beare, S.P.; Lawless, T.A.

doi:10.2118/24974-pa

Cited by 54 publications

(22 citation statements)

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“…• The measured changes in rock strength were consistent with industry-accepted IEF osmotic pressure theory [10][11][12] and IEF membrane efficiency theory 13 for shale-fluid interaction. • An IEF with a WPS equal to the West Africa shale connate water salinity (e.g., a 'balanced' activity fluid having a WPS of 150,000 ppm calcium chloride) would have weakened the shale more than the intermediate WPS IEF.…”

Section: Previous Experimental Worksupporting

confidence: 77%

Changing the Safe Drilling Window with Invert Emulsion Drilling Fluids: Advanced Wellbore Stability Modeling Using Experimental Results

et al. 2010

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In today's increasingly complex well designs, often the range in drilling fluid densities required to prevent hole collapse without fracturing the wellbore, i.e. the safe drilling window, is narrow. This is often the case for wells having high angles of deviation, and is of particular concern in extended-reach drilling (ERD) wells. With increasing step-outs, the drilling equivalent circulating density (ECD) continues to climb with increasing measured depth (MD) while the true vertical depth (TVD) remains fairly constant. The net result can be that as horizontal departure lengths continue to increase, the drilling ECD violates the safe drilling window.In a recent study presented to the industry, the effects of changes in the water phase salinity (WPS) of invert emulsion drilling fluids (IEF) were investigated as a function of rock shear failure for two very different shales: a deepwater West Africa shale and a more-competent Oklahoma shale. After a 3-hr exposure time, the changes in rock strength with different WPS levels were measured directly and results were qualitatively consistent for the two shales.In this paper, the effect of changes in the WPS of IEF on the safe drilling window is demonstrated in an ERD drilling scenario. The modeled failure envelope is first examined using conventional elastic modeling. Poroelastic modeling is then used to show the effect of changes in the safe drilling window resulting from changes in pore pressure. As a further step, changes in the safe drilling window are next shown using porochemoelastic wellbore stability modeling, where the effects of invert emulsion drilling fluid chemistry coupled with changes in pore pressure are introduced. The results show that the safe drilling window can be changed with invert emulsion chemistry, and that there is much to be learned using more advanced poroelastic and porochemoelastic modeling techniques. IntroductionThe drilling of challenging wells is often characterized by a narrow safe drilling window, with the fracture initiation pressure as the upper bound and the wellbore hole collapse pressure as the lower bound. For those cases where the collapse pressures are below the pore pressure, the pore pressure then serves as the safe drilling window lower bound. The safe drilling window is commonly gauged in terms of equivalent mud weight (EMW) and represents the acceptable range of density for maintaining wellbore stability. When the wellbore is circulated, for example during drilling operations, the EMW is equivalent in value to the ECD. When the wellbore is static, the EMW is equivalent in value to the equivalent static density (ESD). Depending on the downhole pressure and temperature conditions, the ESD is often not equal to the density measured under ambient conditions, especially when drilling with IEFs. The general equation for calculation of ECD incorporating circulating pressure drop (ΔP) is given in Equation 1:

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Section: Previous Experimental Worksupporting

confidence: 77%

Changing the Safe Drilling Window with Invert Emulsion Drilling Fluids: Advanced Wellbore Stability Modeling Using Experimental Results

et al. 2010

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“…As for the investigations into the relationship between imbibition and ion diffusion, Ballard et al (1994) and Zolfaghari et al (2014) proposed that the ion diffusion rate is similar to the imbibition rate, depending on permeability, porosity, clay content and contact surface area. Ghanbari et al (2013) conducted imbibition/diffusion experiments and found that the behaviors of imbibition curves are well correlated to that of diffusion curves.…”

Section: Introductionmentioning

confidence: 99%

Experimental and numerical study on the relationship between water imbibition and salt ion diffusion in fractured shale reservoirs

Liu

Shi

et al. 2017

Journal of Natural Gas Science and Engineering

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a b s t r a c tField observations demonstrate that shale gas wells feature a low flowback efficiency (<30%) and highsalinity flowback water (approximately 200kppm) after multistage hydraulic fracturing operations. The water recovery and salinity profile could be regarded as a critical method for volumetric and chemical analyses to characterize the reservoir properties and complexity of the fractured network. This paper aims to understand the relationship between fracturing imbibition and ion diffusion, which are responsible for inefficient water recovery and high-salinity flowback fluid, respectively. Comparative imbibition experiments are performed on different shale and sandstone samples, and an electrical conductivity meter is used to monitor the change in ion concentration change of the imbibition fluid. A mathematical model based on theoretical analysis is proposed to clarify the correlation between imbibition and ion diffusion. Both the experimental and analytical solution results show that the imbibition fluid conductivity resulting from ion diffusion is proportional to the square root of time, which is similar to the law of capillary-driven imbibition into porous media. Water imbibition into gas shale and ion diffusion into water proceed simultaneously in the opposite direction, and only the imbibition front contacting the pore wall with salt ions can cause the salt ions to dissolve and diffuse into water. The analytical solution results also indicate that the effects of the porosity, surface tension, contacting area and wetting angle on the water imbibition rate are in consistent with that of the ion diffusion rate. The permeability, however, shows a positive correlation with the imbibition rate and a negative correlation with the ion diffusion rate. The initial water saturation is negatively related to the imbibition rate, and positively related to the ion diffusion rate. In addition, smectite and I/S could enhance the imbibition and diffusion rates. It is observed that illite concentration has no relationship with the imbibition and diffusion rates, indicating that illite minerals do not significantly affect the imbibition/diffusion rate in these clay-rich shales. This research contributes to understanding the correlation between imbibition and ion diffusion, which is significant for flow-back analysis after fracturing operations.

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“…This result can be partially explained by osmosis effect. The electrically charged clay layers existing in the shale samples can act as semi-permeable membrane that restrict the passage of solute without affecting the passage of solvent (Steiger 1982;Mitchel 1993;Ballard et al 1994). Once low salinity water contacts with the clay particle existing in the shale samples, water molecules flow from low salinity side (imbibition fluid) of semi-permeable membrane to the high salinity side (pore water).…”

Section: Comparison Of Water Imbibition In Confined and Unconfined Samentioning

confidence: 99%

Advances in Understanding Liquid Flow in Gas Shales

Ghanbari

Dehghanpour

et al. 2014

Day 1 Tue, September 30, 2014

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Understanding water uptake of gas shales is critical for designing fracturing and treatment fluids. Previous imbibition experiments on unconfined gas shales have led to several key observations. The water uptake of dry shales is higher than their oil uptake. Furthermore, water imbibition results in sample expansion and microfracture induction. This study provides additional experimental data to understand the effects of rock fabric, complex pore network, and clay swelling on imbibition behavior.We systematically measure the imbibition rates of fresh water, brine and oil into the confined and unconfined rock samples and crushed packs from different shale members of the Horn River Basin. We also measure the ion diffusion rate from shale into water during imbibition experiments. The results show that confining the shale samples decreases the water imbibition rate of samples tested parallel to the bedding. However, it has a negligible effect on water uptake of samples tested perpendicular to the bedding and on ion diffusion rates. The comparative study suggests that, for both confined and unconfined samples, water uptake is higher than oil uptake. The liquid imbibition and ion diffusion rates along the bedding are higher than those against the bedding. Surprisingly, the crushed samples show a completely different behavior. The oil uptake of crushed packs is higher than their water uptake. The data suggest that the connected pore network of the intact samples is water wet while the majority of rock including poorly connected pores is oil wet. This argument is backed by complete spreading of oil on fresh break surfaces of the rock.

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Fundamentals of Shale Stabilization: Water Transport Through Shales

Cited by 54 publications

References 1 publication

Changing the Safe Drilling Window with Invert Emulsion Drilling Fluids: Advanced Wellbore Stability Modeling Using Experimental Results

Changing the Safe Drilling Window with Invert Emulsion Drilling Fluids: Advanced Wellbore Stability Modeling Using Experimental Results

Experimental and numerical study on the relationship between water imbibition and salt ion diffusion in fractured shale reservoirs

Advances in Understanding Liquid Flow in Gas Shales

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