Polymer Flooding in North Sea Reservoirs

Abstract

The use of polymer solutions to enhance oil-displacement efficiency by seawater injection in North Sea oil reservoirs has been investigated. We have evaluated over 140 polymers for viscosity retention and porous media flow performance under high temperature (90 deg. C), high salinity, and high pressure. Scleroglucan polymers give the best performance in our tests. Polyacrylamides (PAAm's) are particularly unsuitable for mobility control. Using polymers to enhance seawater injection and waterflooding processes is not practical in North Sea reservoirs, but selective injection may improve local sweep efficiencies. Introduction North Sea Waterflooding With 95% of Ne crude oil reserves of Western Europe and 90% of the current crude oil production coming from deposits lying under the North Sea bed, oil producers have been prepared to exploit them by making the high capital investment in the new technology of deepwater production platforms. Seawater injection schemes have been introduced early in the life of many/ North Sea fields, and are featuring in Middle East and North and South American offshore field development programs. Most North Sea oils are fairly light, and many can be produced at high rates from thick oil zones in good permeability sandstone reservoirs. The principal aim of the injection schemes has been to maintain reservoir pressure with peripheral injectors positioned mainly below the oil/water contact. Until now, the main problem has been to keep the seawater injection rates high enough. With the incentive of producing more of the North Sea oil reserves, research is being done to ameliorate some other foreseeable problems. One major problem is the severe channeling of injection water, leading to seawater breakthrough into production wells, and the likelihood of barium sulfate scale formation. Channeling resulting from mobility ration effects may be through high-permeability layers (most North Sea reservoirs are very heterogeneous), fractures, or viscous oils. Another factor reducing efficiency is the general rise of the oil/water contact, causing the producing wells to cut excessive quantities of water. Selectively placed polymer injection treatments may reduce channeling, and polymer squeeze treatments may restrict water production. Polymers and other chemical additives need to have adequate chemical stability in the high-salinity, high-temperature environment of North Sea oil reservoirs. Accurate prediction of reservoir performance of enhanced oil recovery (EOR) techniques requires precise data on the behavior of crude oils and relevant aqueous systems in porous media at reservoir conditions. This paper reports thermal stability and porous media test results for a range of polymer types and discusses their possible use to augment North Sea waterflooding. Experimental Polymers Tested. We screened more than 140 polymers, which we classify as polyacrylamides (PAAm's), polyvinylpyrrolidones (PVP's), hydroxyethylcelluloses (HEC's), cellulose sulfate esters (CSE's), guar gums, xanthans, and scleroglucans. Solution Preparation. Solutions were made up in the manner of Hill et al. in seawater (0.45 um filtered) obtained from Chesil beach on the English southwest coast. The seawater contained residual (less than 0.2 ppm) hypochlorite biocide, from a treatment added on collection. Polymer solutions were characterized by filtration profiles through 5-um Millipore filters (at 0.069-MPa driving pressure, and following prefiltration) and by Brookfield ultralow viscometer measurements at 25 and 55 deg. C, with parameters to represent the solution viscosity at high and low shear rates. SPEJ P. 353^

Stability of Partially Hydrolyzed Polyacrylamides at Elevated Temperatures in the Absence of Divalent Cations

“…After 3 days at 120°C or greater, the viscosities either held steady or began to decrease, suggesting that the hydrolysis reaction was nearly complete. This behavior is consistent with previous literature reports ( Davison and Mentzer 1982;Moradi-Araghi and Doe 1987;Ryles 1988).…”

“…HPAM polymers are known to be unstable at elevated temperatures if divalent cations are present (Davison and Mentzer 1982;Zaitoun and Potie 1983;Moradi-Araghi and Doe 1987;Ryles 1988). For temperatures greater than 60°C, acrylamide groups within the HPAM polymer experience hydrolysis to form acrylate groups.…”

Stability of Partially Hydrolyzed Polyacrylamides at Elevated Temperatures in the Absence of Divalent Cations

“…1-8), suggesting that the hydrolysis reaction was nearly complete. This behavior is consistent with previous literature reports ( Davison and Mentzer 1982, Ryles 1988. Although a small amount of ammonium was generated during the hydrolysis reaction, pH changes were minor during the course of our studies.…”

“…HPAM polymers are known to be unstable at elevated temperatures if divalent cations are present (Davison and Mentzer 1982, Zaitoun and Potie 1983, Ryles 1988). For temperatures above 60ºC, acrylamide groups within the HPAM polymer experience hydrolysis to form acrylate groups.…”

Physicochemical properties of (1 → 6)‐branched (1 → 3)‐β‐D‐glucans. 1. Physical dimensions estimated from hydrodynamic and electron microscopic data

“…17J8 This class of polysaccharides has also been suggested as viscosifiers for polymer flooding in hightemperature oil reservoirs because their thermal stability surpasses that of the most commonly discussed biopolymer in this context, xanthan extruded from Xanthomonas campestris. 19,20 At temperatures up to 105OC, which is below the melting temperature of the triple-helical structure at 135'C, scleroglucan was reported to be thermally stable (resistant against breakdown into shorter chains) for more than 400 days." This exceeds that of almost any other biopolymer used for oil recovery.…”