Effects of Gelant Composition and Pressure Gradients of Water and Oil on Disproportionate Permeability Reduction of Sandpacks Treated With Polyacrylamide-Chromium Acetate Gels

Nguyen, Tuan Q.; Green, Don W.; Willhite, G.P.; McCool, Chris

doi:10.2118/89404-pa

Cited by 25 publications

(26 citation statements)

References 14 publications

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“…Although it is possible that gel dehydration was responsible for the gains in oil saturation in these pores, we are inclined to believe that ripping or gel extrusion were more likely the responsible mechanism. We note that in sand packs with permeabilities comparable to our polyethylene core, data from the University of Kansas supports ripping or extrusion mechanisms for creating oil pathways (Seright et al 2006c, Nguyen et al 2006. The hydrophobic polyethylene surface probably allowed a film of oil to penetrate into all pores, where it could act as a lubrication layer to facilitate gel extrusion from the pore.…”

Section: Imbibition and Drainage As A Function Of Throughput After Gementioning

confidence: 55%

“…With a fixed pressure gradient applied through the porous medium, gel in all pores could be "squeezed" or dehydrated to the same extent, regardless of pore size. In very permeable sand packs, data from other researchers supports ripping or extrusion mechanisms for creating oil pathways (Seright et al 2006c, Nguyen et al 2006). …”

Section: Oil Flow After Gel Placementmentioning

confidence: 95%

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Understanding the Rate of Clean Up for Oil Zones after a Gel Treatment

Seright

Lindquist

Cai

2008

SPE Symposium on Improved Oil Recovery

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In our previous work, X-ray computed microtomography (XMT) was used to establish why pore-filling Cr(III)-acetate-HPAM gels reduced permeability to water much more than to oil. Our results suggest that permeability to water was reduced to low values because water must flow through gel itself, whereas oil pressing on the gel in a porous medium forced pathways by dehydration-leading to relatively high permeability to oil. Those studies involved obtaining 3D pore-level Xray images at the saturation endpoints-for example, after forcing 20 pore volumes of oil or water through the core following gel placement.The dependence of oil permeability on oil throughput determines how long it takes for a production well to "clean up" or restore productivity after a gel treatment. Consequently, we were interested in how the gel dehydration process progresses as a function of oil throughput. This paper describes a new study where pore-scale XMT images were obtained at a variety of oil (hexadecane) throughput values after gel placement (involving a pore-filling Cr(III)-acetate-HPAM gel). For each pore in our image volume, we followed oil and water saturations as a function of oil throughput. These studies were performed both in water-wet Berea sandstone and in hydrophobic porous polyethylene. In hydrophobic porous polyethylene, oil saturations increased and gel was destroyed (presumably dehydrated) quite quickly in the smallest pores (10 -6 mm 3 ). Also, oil saturations increased and gel was destroyed quickly in the largest pores (<0.005 mm 3 ). In contrast, oil saturations rose much more gradually for the most common or intermediate-sized pores (around 10 -4 mm 3 , the peak in the pore size distribution). The minimum in oil saturation versus pore size may result from a balance between gel dehydration by oil film growth versus gel extrusion. Presumably, during oil injection after gel placement, an oil film forms with a thickness that is about the same on all polyethylene surfaces. However, because the ratio of film thickness to pore or throat size increases with decreased pore size, gel dehydration occurs faster and more effectively in the smallest polyethylene pores, causing oil saturation to increase with decreased pore size. This effect may lose its signicance for pore sizes above 10 -4 mm 3 . As pore size increases above 10 -4 mm 3 , gel extrusion from the pore becomes more likely-explaining why oil saturation increased with increased pore size for the largest pores.In contrast in water-wet Berea sandstone, increases in oil saturation occurred evenly over all pore sizes (10 -6 to 0.02 mm 3 ) for all oil throughput values. Consistent with imbibition and drainage studies performed before gel placement, oil apparently had equal access to Berea pores of all sizes, and thus uniformly dehydrated gel in pores of all sizes. Gel extrusion did not appear to be significant in the Berea pores.

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Section: Imbibition and Drainage As A Function Of Throughput After Gementioning

confidence: 55%

Section: Oil Flow After Gel Placementmentioning

confidence: 95%

Understanding the Rate of Clean Up for Oil Zones after a Gel Treatment

Seright

Lindquist

Cai

2008

SPE Symposium on Improved Oil Recovery

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“…Due to DPR, the gel has the ability to reduce water permeability more than oil permeability. Various mechanisms have been reported for DPR such as gel shrinkage and swelling, segregated oil and water pathways, dehydration of polymer gel, and trapping of water droplets in its chains . A high selectivity parameter (near 1) indicates an ideal situation in which water permeability decreases after the treatment, but oil permeability is not changed considerably .…”

Section: Resultsmentioning

confidence: 99%

Development of a novel water shut‐off test method: Experimental study of polymer gel in porous media with radial flow

et al. 2015

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Polymer gel treatment is an economic and effective method to reduce excessive water production in hydrocarbon reservoirs. However, there exist unsuccessful applications of polymer gel due to a mismatch of theoretical and experimental results in field conditions. In this study, a gel treatment experiment was implemented using a novel test method which includes a unique two-dimensional coreflooding setup and a new procedure of simultaneous oil and water injection. To form the gel in situ, a Cr(III)-acetate-hydrolyze polyacrylamide (HPAM) gelant was used. The results showed that polymer gel could be successfully applied to water shut-off (WSO) treatments in low-permeable porous media with radial flow. The residual resistance factors for oil and water were 78.50 and 1.96, respectively. Polymer gel also showed disproportionate permeability reduction (DPR) behaviour in coreflooding experiments. The flow resistance to water was 40 times greater than that to oil. In gel treatment, high gel selectivity (DPR scale) of 0.83 was measured by simultaneous oil and water flow to the core, and the determined oil cut was much greater than the water cut, whereas a lower well production rate led to a higher water cut. In addition, a water blockage problem was examined in simultaneous injection at constant pressure. No observation of water in the outlet was reported, though water saturation through the sandpack was increased to 84 %. Finally, this paper suggests a new experimental test to increase the chances of successful WSO treatment under laboratory circumstances close to the field conditions.

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“…Equation (11) shows also that the cooled thickness is a function of the cooled radius and invasion radius. For better design of fluid bullhead injection in multi layered reservoir it is, sometime, necessary to model the temperature distribution in the vertical direction, i.e.…”

Section: Estimating the Thickness Of The Cooled Zonementioning

confidence: 99%

Chemical Injection in Multilayered Reservoir that have Different Rock Properties and Pore Pressures

Ahmed

2012

All Days

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Well intervention techniques and several IOR and EOR methods are sometimes entailing injection of emulsion of water based chemicals and oil into hydrocarbon reservoir layers. The injection depth into each layer usually depends on a lot of different factors that related to reservoir rock and fluid properties as well as the difference between injected fluid's pressure and formation fluid's pressure. For a well completed in multi zones and each zone has its own permeability, porosity, fluid saturation and pore pressure; it is difficult to predict how and up to what end the injection fluid will invade each zone.A computation model, based on analytical equations of flow in porous media, is developed to simulate bullhead injection of water based chemical solutions into well with multi opened zones. Analytical equations are developed to model fluid penetration radius, injected volume and injection rate for every opened zone during the injection process. Equations describe cooling effect of the injected fluid into hot formation is arranged and simulated to illustrate radial and vertical cooled area during the injection process. An equation is developed to simulate dilution process of chemical concentrated solution during its injection into reservoir layer This model is very useful when it comes to plan and to design chemical water shut off, sand consolidation, microbial fluid placement, injection of mobility control fluids or any treatment involves of bullheading of chemical concentrated solutions into multi layered reservoir. It can be also used to design many workover applications especially for comminglely completed wells.

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Effects of Gelant Composition and Pressure Gradients of Water and Oil on Disproportionate Permeability Reduction of Sandpacks Treated With Polyacrylamide-Chromium Acetate Gels

Cited by 25 publications

References 14 publications

Understanding the Rate of Clean Up for Oil Zones after a Gel Treatment

Understanding the Rate of Clean Up for Oil Zones after a Gel Treatment

Development of a novel water shut‐off test method: Experimental study of polymer gel in porous media with radial flow

Chemical Injection in Multilayered Reservoir that have Different Rock Properties and Pore Pressures

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