eprintid: 4555
rev_number: 2
eprint_status: archive
userid: 1
dir: disk0/00/00/45/55
datestamp: 2023-11-09 16:16:14
lastmod: 2023-11-09 16:16:14
status_changed: 2023-11-09 15:58:41
type: conference_item
metadata_visibility: show
creators_name: Kalwar, S.A.
creators_name: Elraies, K.A.
creators_name: Memon, M.K.
creators_name: Kumar, S.
creators_name: Abbas, G.
creators_name: Mithani, A.H.
title: A new approach to ASP flooding in high saline and hard carbonate reservoirs
ispublished: pub
keywords: Calcite; Carbonation; Cost reduction; Enhanced recovery; Floods; Gasoline; Mixing; Petroleum reservoirs; Reservoirs (water); Surface active agents, Carbonate reservoir; Chemical enhanced oil recoveries; Coreflood tests; Formation damage; Parts per millions; Precipitation inhibitors; Scale formation; Surface facilities, Oil well flooding
note: cited By 7; Conference of International Petroleum Technology Conference 2014 - Innovation and Collaboration: Keys to Affordable Energy, IPTC 2014 ; Conference Date: 10 December 2014 Through 12 December 2014; Conference Code:112331
abstract: Chemical Enhanced Oil Recovery (CEOR) has come into focus as a highly effective and versatile EOR method due to recent advances in the technology. However, CEOR particularly Alkali-Surfactant-Polymer (ASP) flooding is challenging in carbonate reservoirs. The main constraints are the undesired minerals such as calcite, dolomite, anhydrite and gypsum consisted of divalent ions. The minerals complex with injected chemicals and form precipitates that cause formation damage and scale formation in wells and surface facilities. This study presents a new Acid-Alkali-Surfactant-Polymer (AASP) flooding formulation as an alternative to conventional ASP flooding. AASP included acrylic acid as a precipitation inhibitor. The new formulation was compatible with the hard brine composition of 59,940 ppm TDS (with 2762 ppm divalent ions) for 30 days at 80 °C. AASP combination also provided acceptable interfacial tension and slug viscosity required for flooding in the presence of hard brine. Additionally, more than 30 Origional Oil in Place (OOIP) was recovered in the natural imbibition tests. Injecting 0.5PV of the optimum AASP formulation slug gave 18.9 OOIP to waterflooding in the coreflood tests. Thus, AASP flooding formulation is viable for suppressing the limitations of ASP flooding in carbonate reservoirs. Although, precipitation inhibitor increases the cost of chemical slug by adding several hundred parts per million (ppm) of inhibitor, significant cost savings will be realized because of the reductions in workover jobs and associated lost of production. Further, AASP flooding formulation also eliminates the need to soften the mixing brine. This will result in expanding the CEOR application to more challenging carbonate reservoirs and reduce the softening cost for mixing water. Copyright © 2014, International Petroleum Technology Conference.
date: 2014
publisher: Society of Petroleum Engineers
official_url: https://www.scopus.com/inward/record.uri?eid=2-s2.0-84934281633&doi=10.2523%2fiptc-17809-ms&partnerID=40&md5=3de75a8a6a0ec43ca11db196822613f9
id_number: 10.2523/iptc-17809-ms
full_text_status: none
publication: Society of Petroleum Engineers - International Petroleum Technology Conference 2014, IPTC 2014 - Innovation and Collaboration: Keys to Affordable Energy
volume: 2
pagerange: 986-996
refereed: TRUE
isbn: 9781634398350
citation:   Kalwar, S.A. and Elraies, K.A. and Memon, M.K. and Kumar, S. and Abbas, G. and Mithani, A.H.  (2014) A new approach to ASP flooding in high saline and hard carbonate reservoirs.  In: UNSPECIFIED.