Compaction-induced porosity/permeability reduction in sandstone reservoirs: <i>Data and model for elasticity-dominated deformation</i>

Schutjens, Peter; Hanssen, T.H.; Hettema, M.H.H.; Merour, J.; Bree, J.e; Coremans, J.W.A.; Helliesen, G.

doi:10.2118/71337-ms

Cited by 20 publications

(3 citation statements)

References 30 publications

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“…For the reservoir rock, for which we set an initial porosity φ 0 = 16%, laboratory experiments have shown that permeability changes significantly less than 1 order of magnitude [ Schutjens et al ., ]. We apply a permeability law that is based on the modified Kozeny‐Carman relationship, which is commonly used to model permeability changes in reservoir rocks [ Zoback , , and references therein]:

κ = κ_{0} {(\frac{φ - φ_{c}}{φ_{0} - φ_{c}})}^{3} {(\frac{1 + φ_{c} - φ_{0}}{1 + φ_{c} - φ})}^{2}

where φ c is the percolation porosity, which is the limiting porosity at which the pores are disconnected and no longer contribute to flow.…”

Section: Model Setupmentioning

confidence: 99%

On the physics‐based processes behind production‐induced seismicity in natural gas fields

Zbinden¹,

Rinaldi²,

Urpi³

et al. 2017

JGR Solid Earth

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Induced seismicity due to natural gas production is observed at different sites worldwide. Common understanding states that the pressure drop caused by gas production leads to compaction, which affects the stress field in the reservoir and the surrounding rock formations and hence reactivates preexisting faults and induces earthquakes. In this study, we show that the multiphase fluid flow involved in natural gas extraction activities should be included. We use a fully coupled fluid flow and geomechanics simulator, which accounts for stress‐dependent permeability and linear poroelasticity, to better determine the conditions leading to fault reactivation. In our model setup, gas is produced from a porous reservoir, divided into two compartments that are offset by a normal fault. Results show that fluid flow plays a major role in pore pressure and stress evolution within the fault. Fault strength is significantly reduced due to fluid flow into the fault zone from the neighboring reservoir compartment and other formations. We also analyze scenarios for minimizing seismicity after a period of production, such as (i) well shut‐in and (ii) gas reinjection. In the case of well shut‐in, a highly stressed fault zone can still be reactivated several decades after production has ceased, although on average the shut‐in results in a reduction in seismicity. In the case of gas reinjection, fault reactivation can be avoided if gas is injected directly into the compartment under depletion. However, gas reinjection into a neighboring compartment does not stop the fault from being reactivated.

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κ = κ_{0} {(\frac{φ - φ_{c}}{φ_{0} - φ_{c}})}^{3} {(\frac{1 + φ_{c} - φ_{0}}{1 + φ_{c} - φ})}^{2}

where φ c is the percolation porosity, which is the limiting porosity at which the pores are disconnected and no longer contribute to flow.…”

Section: Model Setupmentioning

confidence: 99%

On the physics‐based processes behind production‐induced seismicity in natural gas fields

Zbinden¹,

Rinaldi²,

Urpi³

et al. 2017

JGR Solid Earth

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“…For this study, a failure criterion with a cap to represent pore collapse was used. This cap model was originally developed by NGI for application to sandstone reservoirs by Schutjens et al (2004) and later applied to carbonate reservoirs.…”

Section: Spe-171993-msmentioning

confidence: 99%

Prediction of Reservoir Formation Collapse in a Carbonate Gas Field in Abu Dhabi UAE Using Coupled Reservoir Geomechanical Modelling

Sirat

Ammari

Masoud

et al. 2014

Abu Dhabi International Petroleum Exhibition and Conference

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Formation collapse in reservoirs where the pressure has not been maintained during depletion can cause permeability reduction, completion damage and well failure, interrupting production and affecting the ultimate recovery from the reservoir. The problem is particularly acute within severely depleted areas of the field.In this paper a carbonate gas field was investigated. For this developed field, a further production plan has been scheduled to deplete the reservoir up to the year 2063 without any reservoir pressure maintenance. The objective of this study is to investigate the possibility of formation collapse of the productive zone, well failure and completion integrity damage particularly within the severely depleted areas. Coupled reservoir geomechanical modelling was conducted, and different scenarios were investigated to understand the impact of uncertainty in mechanical properties and the presence of faults and fractures.The results indicate that pore collapse is likely to be the main failure mechanism of high porosity formations with high levels of depletion. Onset of formation failure is likely to happen around 2018 to 2020, and it is recommended to monitor the production rate of those wells located in high porosity and high depletion areas. Pressure maintenance should be implemented if the reservoir pressure falls below 1000 psi in the later stages of production.

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“…The precipitation of these salts can lead to disastrous damage in building and statues made with porous materials. ,,,,,, This damage can be made worse by treatments that aim to waterproof the building materials as this can encourage subflorescence that weakens the outer layer . Pore network models have also been used to study and predict drying of pure liquid porous media without salt precipitation ,− and to study combined evaporation and salt precipitation in porous media. ,, Also, for CO 2 sequestration processes, precipitation of salts, mainly consisting of halite (NaCl), can be a serious source of problems during CO 2 injection because this can lead to reductions in porosity and permeability of the reservoir in the vicinity of the wellbore. ,,− Oil reservoirs have a wide range of wetting states, − and given the strong influence of capillary forces outlined above, this may have a significant impact on halite deposition. The effect of these different porous media wetting states on the different stages of evaporation and the subsequently deposited salt is not well understood and remains one of the open problems in the field, especially during the storage of supercritical CO 2 in depleted oil and gas reservoirs.…”

Section: Introductionmentioning

confidence: 99%

Effect of Wettability Changes on Evaporation Rate and the Permeability Impairment due to Salt Deposition

Rufai

Crawshaw

2018

ACS Earth Space Chem.

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Pore-scale visualization was employed to investigate evaporative drying of brine and associated salt deposition at different wetting conditions, using a 2.5D etchedsilicon/glass micromodel based on a thin section image of a carbonate rock. We also compared air drying with CO 2 drying, with the latter having important applications in CO 2 sequestration processes. The resulting permeability impairment was also measured.For deionized-water in a water-wet model, we observed the three classical periods of evaporation: the constant rate period (CRP), the falling rate period (FRP) and the receding front period (RFP). The length of the deionized-water CRP was much shorter for a uniformly oil-wet model, but mixed wettability made little difference to the drying process. For brine systems at all wetting conditions, the dry area became linear with the square root of time after a short CRP. Although this is due to the deposited salt acting as a physical barrier to hydraulic connectivity, unlike the case of deionized-water which is due to capillary disconnection from the fracture channel.For water-wet model, we observed two regions of a linear downward trend in the matrix and fracture permeability measurements. A similar trend was observed for the mixed-wet systems. However, for the oil-wet systems, fracture permeability only changes slightly even for 360g/L brine, a result of the absence of salt deposits in the fracture caused by the early rupture of the liquid wetting films needed to aid hydraulic connectivity. Overall, matrix permeability for all wetting conditions decreased with increasing brine concentration and was almost total for the 360g/L brine. Finally, using CO 2 rather than air as carrier gas makes the brine phase more wetting especially in the deionized-water case, with the result that hydraulic connectivity was maintained for longer in the CO 2 case compared to dry-out with air.

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Compaction-induced porosity/permeability reduction in sandstone reservoirs: Data and model for elasticity-dominated deformation

Cited by 20 publications

References 30 publications

On the physics‐based processes behind production‐induced seismicity in natural gas fields

On the physics‐based processes behind production‐induced seismicity in natural gas fields

Prediction of Reservoir Formation Collapse in a Carbonate Gas Field in Abu Dhabi UAE Using Coupled Reservoir Geomechanical Modelling

Effect of Wettability Changes on Evaporation Rate and the Permeability Impairment due to Salt Deposition

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