Occurrence, Prediction, and Prevention of Zinc Sulfide Scale Within Gulf Coast and North Sea High-Temperature and High-Salinity Fields

2003 ◽  
Vol 18 (03) ◽  
pp. 200-209 ◽  
Author(s):  
I.R. Collins ◽  
M.M. Jordan
Keyword(s):  
High Temperature ◽  
Zinc Sulfide ◽  
North Sea ◽  
High Salinity ◽  
Gulf Coast ◽  
Prediction And Prevention

Polymer Flooding in North Sea Reservoirs

1982 ◽  
Vol 22 (03) ◽  
pp. 353-362 ◽  
Author(s):  
Paul Davison ◽  
Eric Mentzer
Keyword(s):  
Porous Media ◽  
High Temperature ◽  
North Sea ◽  
High Salinity ◽  
Oil Reservoirs ◽  
Water Contact ◽  
Oil Reserves ◽  
The North ◽  
The North Sea ◽  
Oil Water

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^

Development and Evaluation of Ultra-High Temperature Resistant Preformed Particle Gels for Conformance Control in North Sea Reservoirs

2021 ◽  
Author(s):  
Thomas Schuman ◽  
Buddhabhushan Salunkhe ◽  
Ali Al Brahim ◽  
Baojun Bai
Keyword(s):  
Thermal Stability ◽  
High Temperature ◽  
North Sea ◽  
Open Fracture ◽  
High Salinity ◽  
Core Flooding ◽  
Swelling Rate ◽  
Higher Temperature ◽  
Preformed Particle Gels

Abstract Preformed particle gels (PPGs), a type of hydrogel, have been widely applied to control the conformance of reservoirs owing to their robust gel chemistries. Traditional PPGs are polyacrylamide-based hydrogel compositions which can withstand neither higher temperatures nor high salinity conditions. There are many deep oilfield reservoirs worldwide which demand PPG products with a long term hydrolytic and thermal stability at the temperatures of higher than 120 °C. Current PPGs neither remain hydrated nor retain polymer integrity at these temperatures. A unique high temperature-resistant hydrogel composition (HT-PPG) was developed with exceptional thermal stability for greater than 18 months in North Sea formation temperature (~130 °C) and formation water environments. HT-PPG described herein can swell up to 30 times its initial volume in brines of different salinity for North Sea. The effects of salinity and temperature on swelling, swelling rate, and rheological behavior was studied. These HT-PPGs exhibit excellent strength with storage modulus (G’) of over 3,000 Pa at the swelling ratio of 10. Thermostability evaluations were performed in North Sea brines with variable salinity at temperatures of 130 °C and 150 °C and found to be stable for 18 months with no loss of molecular integrity at the higher temperature. Laboratory core flooding tests were conducted to test its plugging efficiency to fracture. HT-PPGs showed good plugging efficiency by reducing the permeability of open fracture and did not wash out during waterflooding. Overall, HT-PPG is a novel product with excellent hydrothermal stability that make it an ideal candidate for conformance problems associated with reservoirs of high temperature and salinity conditions.

A Novel Hydroxylpropyl Sulfobetaine Surfactant for High Temperature and High Salinity Reservoirs

2013 ◽  
Author(s):  
Fan Zhang ◽  
Desheng Ma ◽  
Qiang Wang ◽  
Youyi Zhu ◽  
Wenli Luo
Keyword(s):  
High Temperature ◽  
High Salinity
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