Transport in Shales and the Design of Improved Water-Based Shale Drilling Fluids

Oort, Eric van; Hale, A.H.; Mody, F.K.; Roy, Sanjit Kumar

doi:10.2118/28309-pa

Cited by 176 publications

(61 citation statements)

References 26 publications

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“…Eqs. (6) and (11), are solved numerically using the finite difference method to obtain pore pressure and moisture content around the borehole. For sensitivity analysis, three shale formations were selected (shale C, Midway and Mancos) to cover wide range of affinity of shale toward aqueous fluid.…”

Section: Modeling Results and Discussionmentioning

confidence: 99%

“…Eqs. (6) and (11), is subjected to the following initial and boundary conditions: (13-c) where sh a and a df are the in-situ water activity of shale and water activity of the drilling fluid, respectively. Also, P o and P wb represent the in-situ pore pressure and wellbore pressure, respectively.…”

Section: A Diffusion-sorption Modelmentioning

confidence: 99%

“…Hydration of clay minerals is recognized to be one of the important interaction processes between shale and drilling fluid during drilling process, which often leads to various operational problems such as shale swelling, stuck pipe, reduction of rate of penetration [6,7]. Usually two kinds of clay swelling is realized, namely, the interacrystalline swelling due to the hydration of exchangeable cations and osmotic swelling which occurs due to a large difference between ion concentration (or water activity) of shale and aqueous fluids [8][9][10].…”

mentioning

confidence: 99%

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Effects of Sorptive Tendency of Shale on Borehole Stability

Dokhani¹,

Yu²

2016

JGRE

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Abstract:Interactions between aqueous drilling fluids and clay minerals have been identified as an important factor in wellbore instability of shale formations. Current wellbore stability models consider the interactions between aqueous drilling fluids and pore fluid but the interactions with shale matrix are neglected. This study provides a realistic method to incorporate the interaction mechanism into wellbore stability analysis through laboratory experiment and mathematical modeling. The adsorption isotherms of two shale rocks, Catoosa Shale and Mancos Shale are obtained. The adsorption isotherms of the selected shales are compared with those of other shale types in the literature. This study shows that the adsorption theory can be used to generalize wellbore stability problem in order to consider the case of non-ideal drilling fluids. Furthermore, the adsorption model can be combined with empirical correlations to update the compressive strength of shale under downhole conditions. Accordingly, a chemo-poro-elastic wellbore stability simulator is developed to explore the stability of transversely isotropic shale formations. The coupled transport equations are solved using an implicit finite difference method. The results of this study indicate that the range of safe mud weight reduces due to the moisture adsorption phenomenon.

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Section: Modeling Results and Discussionmentioning

confidence: 99%

Section: A Diffusion-sorption Modelmentioning

confidence: 99%

mentioning

confidence: 99%

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Effects of Sorptive Tendency of Shale on Borehole Stability

Dokhani¹,

Yu²

2016

JGRE

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“…The permeability of shale is often in the nano-Darcy scale or even lower (Figures 3a and 3b). The caprock is composed of shale layers (Maldal and Tappel 2004) and due to the low permeability of compacted clays, shale zones can easily become overpressured (Chenevert and Sharma 1991;Katsube et al 1991;Van Oort et al 1996).…”

Section: Geological Model and "Leakage" Scenarios Geological Zonesmentioning

confidence: 99%

Simulating seismic chimney structures as potential vertical migration pathways for CO2 in the Snøhvit area, SW Barents Sea: model challenges and outcomes

et al. 2016

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Carbon Capture and Storage (CCS) activities at the Snøhvit field, Barents Sea, will involve carrying out an analysis to determine which parameters affect the migration process of CO2 from the gas reservoir, to what degree they do so and how sensitive these parameters are to any changes. This analysis will aim to evaluate the effects of applying a broad but realistic range of reservoir, fault and gas chimney properties on potential CO2 leakage at various depths throughout the subsurface. Fluid flow might take place through parts of or the entire extent of the overburden. One of the aims of the analysis is assessing the potential of CO2 reaching the seabed. Using the Snøhvit gas reservoir and overburden in the Barents Sea, a series of geological models were built using seismic and well-log data. We then performed numerical simulations of CO2 migration in focused fluid flow structures. Identification of potential migration pathways and their extent, such as gas chimneys and faults, and their incorporation into these models and simulations will provide a realistic insight into the migration potential of CO2. In the simulations the CO2 is injected over a 20 year period at a rate of 0.7 Mt/year and migration is allowed to take place over a 2000 year time frame for domains of approximately 21 Km 2 for the caprock fault models, 24 Km 2 for the realistic gas chimney models and 35 Km 2 for the generic gas chimney models, in a layered sedimentary succession. The total mass of CO2 injected in the reservoir during the 20-year injection period is 14 Mt. There is a strong interaction between the various parameters but the parameter that had the most influence on the CO2 migration process was probably the permeability of the reservoirs, especially the average permeability (k). Also, for the faulted caprock scenarios, it should be noted that at near surface depths the permeability of 765 mD is already adequate for a good CO2 flow. At the chimney top level (600 m) however, a further increase in permeability has an additional effect on improving CO2 flow. Overall, considering the slow upward migration velocity of the plume, this geological setup can be regarded as a suitable storage site.

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“…In the oil and gas industry, 75% of all footage was drilled in shale formations which are responsible for 90% of wellbore stability problems [1][2][3]. The main cause of shale instability for both soft and hard shales is water absorption and the subsequent swelling and sloughing of the wellbore [4].…”

Section: Introductionmentioning

confidence: 99%

2D Numerical Simulation of Improving Wellbore Stability in Shale Using Nanoparticles Based Drilling Fluid

Song

Yuan²,

et al. 2017

Energies

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Abstract:The past decade has seen increased focus on nanoparticle (NP) based drilling fluid to promote wellbore stability in shales. With the plugging of NP into shale pores, the fluid pressure transmission can be retarded and wellbore stability can be improved. For better understanding of the interaction between shale and NP based drilling fluid based on previous pressure transmission tests (PTTs) on Atoka shale samples, this paper reports the numerical simulation findings of wellbore stability in the presence of NP based drilling fluid, using the 2D fluid-solid coupling model in FLAC3D™ software. The results of previous PTT are discussed first, where the steps of numerical simulation, the simulation on pore fluid pressure transmission, the distribution of stress and the deformation of surrounding rock are presented. The mechanisms of NP in reducing permeability and stabilizing shale are also discussed. Results showed that fluid filtrate from water-based drilling fluid had a strong tendency to invade the shale matrix and increase the likelihood of wellbore instability in shales. However, the pore fluid pressure near wellbore areas could be minimized by plugging silica NP into the nanoscale pores of shales, which is consistent with previous PTT. Pore pressure transmission boundaries could also be restricted with silica NP. Furthermore, the stress differential and shear stress of surrounding rock near the wellbore was reduced in the presence of NP. The plastic yield zone was minimized to improve wellbore stability. The plugging mechanism of NP may be attributed to the electrostatic and electrodynamic interactions between NP and shale surfaces that are governed by Derjaguin-Landau-Verwey-Overbeek (DLVO) forces, which allowed NP to approach shale surfaces and adhere to them. We also found that discretization of the simulation model was beneficial in distinguishing the yield zone distribution of the surrounding rock in shales. The combination of PTT and the 2D numerical simulation offers a better understanding of how NP-based drilling fluid can be developed to address wellbore stability issues in shales.

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Transport in Shales and the Design of Improved Water-Based Shale Drilling Fluids

Cited by 176 publications

References 26 publications

Effects of Sorptive Tendency of Shale on Borehole Stability

Effects of Sorptive Tendency of Shale on Borehole Stability

Simulating seismic chimney structures as potential vertical migration pathways for CO2 in the Snøhvit area, SW Barents Sea: model challenges and outcomes

2D Numerical Simulation of Improving Wellbore Stability in Shale Using Nanoparticles Based Drilling Fluid

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