Study of action mechanisms and properties of Cr3+ cross-linked polymer solution with high salinity

Abstract Over the last few years, ADNOC has systematically investigated a new polymer-based EOR scheme to improve sweep efficiency in high temperature and high salinity (HTHS) carbonate reservoirs in Abu Dhabi (Masalmeh et al., 2014). Consequently, ADNOC has developed a thorough de-risking program for the new EOR concept in these carbonate reservoirs. The de-risking program includes extensive laboratory experimental studies and field injectivity tests to ensure that the selected polymer can be propagated in the target reservoirs. A new polymer with high 2-acrylamido-tertiary-butyl sulfonic acid (ATBS) content was identified, based on extensive laboratory studies (Masalmeh, et al., 2019, Dupuis, et al., 2017, Jouenne 2020), and an initial polymer injectivity test (PIT) was conducted in 2019 at 250°F and salinity >200,000 ppm, with low H2S content (Rachapudi, et al., 2020, Leon and Masalmeh, 2021). The next step for ADNOC was to extend polymer application to harsher field conditions, including higher H2S content. Accordingly, a PIT was designed in preparation for a multi-well pilot This paper presents ADNOC's follow-up PIT, which expands the envelope of polymer flooding to dissolve H2S concentrations of 20 - 40 ppm to confirm injectivity at representative field conditions and in situ polymer performance. The PIT was executed over five months, from February 2021 to July 2021, followed by a chase water flood that will run until December 2021. A total of 108,392 barrels of polymer solution were successfully injected during the PIT. The extensive dataset acquired was used to assess injectivity and in-depth mobility reduction associated with the new polymer. Preliminary results from the PIT suggest that all key performance indicators have been achieved, with a predictable viscosity yield and good injectivity at target rates, consistent with the laboratory data. The use of a down-hole shut-in tool (DHSIT) to acquire pressure fall-off (PFO) data clarified the near-wellbore behaviour of the polymer and allowed optimisation of the PIT programme. This paper assesses the importance of water quality on polymer solution preparation and injection performance and reviews operational data acquired during the testing period. Polymer properties determined during the PIT will be used to optimise field and sector models and will facilitate the evaluation of polymer EOR in other giant, heterogeneous carbonate reservoirs, leading to improved recovery in ADNOC and Middle East reservoirs.

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Polymer in-Situ Rheology in Carbonate Reservoirs

10.2118/207286-ms ◽

2021 ◽

Author(s):

Tormod Skauge ◽

Kenneth Sorbie ◽

Ali Al-Sumaiti ◽

Shehadeh Masalmeh ◽

Arne Skauge

Keyword(s):

Polymer Solution ◽

Carbonate Rock ◽

High Salinity ◽

Polymer Flooding ◽

Resistance Factor ◽

Carbonate Reservoirs ◽

Permeability Reduction ◽

Polymer Flood ◽

Core Flood

Abstract A large, untapped EOR potential may be extracted by extending polymer flooding to carbonate reservoirs. However, several challenges are encountered in carbonates due to generally more heterogeneous rock and lower permeability. In addition, high salinity may lead to high polymer retention. Here we show how in-situ viscosity varies with permeability and heterogeneity in carbonate rock from analysis of core flood results and combined with review of data available in literature. In-situ rheology experiments were performed on both carbonate outcrop and reservoir cores with a range in permeabilities. The polymer used was a high ATBS content polyacrylamide (SAV10) which tolerates high temperature and high salinity. Some cores were aged with crude oil to generate non-water-wet, reservoir representative wettability conditions. These results are compared to a compilation of literature data on in-situ rheology for predominantly synthetic polymers in various carbonate rock. A systematic approach was utilized to derive correlations for resistance factor, permeability reduction and in-situ viscosity as a function of rock and polymer properties. Polymer flooding is applied to improve sweep efficiency that may occur due to reservoir heterogeneities (large permeability contrasts, anisotropy, thief zones) or adverse mobility ratio (high mobility contrast oil-brine). In flooding design, the viscosity of the polymer solution in the reservoir, the in-situ viscosity, is an essential parameter as this is tuned to correct the mobility difference and to improve sweep. The viscosity is estimated from rheometer/viscometer measurements or, better, measured in laboratory core flood experiments. However, upscaling core flood experiments to field is challenging. Core flood experiments measure differential pressure, which is the basis for the resistance factor, RF, that describes the increased resistance to flow for polymer relative to brine. However, the pressure is also influenced by several other factors such as the permeability reduction caused by adsorption and retention of polymer in the rock, the tortuosity of the rock and the viscosity of the flowing polymer solution. Deduction of in-situ viscosity is straight forward using Darcy's law but the capillary bundle model that is the basis for applying this law fails for non-Newtonian fluids. This is particularly evident in carbonate rock. Interpretation of in-situ rheology experiments can therefore be misleading if the wrong assumptions are made. Polymer flooding in carbonate reservoirs has a large potential for increased utilization of petroleum reserves at a reduced CO2 footprint. In this paper we apply learnings from an extensive core flood program for a polymer flood project in the UAE and combine this with reported literature data to generate a basis for interpretation of in-situ rheology experiments in carbonates. Most importantly, we suggest a methodology to screen experiments and select data to be used as basis for modelling polymer flooding. This improves polymer flood design, optimize the polymer consumption, and thereby improve project economy and energy efficiency.

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Pore Scale Modelling of Linked Polymer Solution (LPS) – A New EOR Process

IOR 2009 - 15th European Symposium on Improved Oil Recovery ◽

10.3997/2214-4609.201404822 ◽

2009 ◽

Cited By ~ 1

Author(s):

S. Fallah Bolandtaba ◽

A. Skauge ◽

E. MacKay

Keyword(s):

Polymer Solution ◽

Pore Scale ◽

Scale Modelling ◽

Linked Polymer Solution

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Mechanism and gelling effects of linked polymer solution in the core

Petroleum Exploration and Development ◽

10.1016/s1876-3804(13)60065-8 ◽

2013 ◽

Vol 40 (4) ◽

pp. 507-513 ◽

Cited By ~ 20

Author(s):

Jinxiang LIU ◽

Xiangguo LU ◽

Jingfa LIU ◽

Shuqiong HU ◽

Baoqing XUE

Keyword(s):

Polymer Solution ◽

The Core ◽

Linked Polymer Solution

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A Study of Thermal Stability of Linked Polymer Solution

Journal of Dispersion Science and Technology ◽

10.1080/01932690802643154 ◽

2009 ◽

Vol 30 (6) ◽

pp. 753-756 ◽

Cited By ~ 7

Author(s):

Meiqin Lin ◽

Mingyuan Li ◽

Zhaojun Wang ◽

Zhaoliang Wu

Keyword(s):

Thermal Stability ◽

Polymer Solution ◽

Thermal Stability Of ◽

Linked Polymer Solution

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Influence of dissolved oxygen content on oxidative stability of linked polymer solution

Petroleum Science ◽

10.1007/s12182-009-0064-2 ◽

2009 ◽

Vol 6 (4) ◽

pp. 421-425 ◽

Cited By ~ 2

Author(s):

Zhao-xia Dong ◽

Mei-qin Lin ◽

Jian Xin ◽

Ming-yuan Li

Keyword(s):

Dissolved Oxygen ◽

Oxidative Stability ◽

Polymer Solution ◽

Oxygen Content ◽

Linked Polymer Solution

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The Adaptability in Polymer Flooding to GuoPu Oilfield of Childers - Jayne Childers

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.997.284 ◽

2014 ◽

Vol 997 ◽

pp. 284-287

Author(s):

Yin Feng Liu ◽

Da Zhao Song ◽

Yu Yao ◽

Bi Yun Fu

Keyword(s):

Low Temperature ◽

Polymer Solution ◽

Mass Fraction ◽

High Salinity ◽

Polymer Degradation ◽

Polymer Flooding ◽

Temperature Relationship ◽

Cross Linking ◽

Reservoir Conditions ◽

The Stability

In view of the actual conditions of childers - jayne GuoPu reservoir with low temperature, high salinity , this text select three kinds of polymer by evaluating the related parameters of polymer which is resistant to high salinity to discuss the performance and adaptability.From the polymer viscosity-concentration relationship and viscosity-temperature relationship, it can be concluded that when the concentration of the HDSJ is 3000 mg/L, it can meet the requirements of the theory of reservoir viscosity values.However, due to the specific conditions of reservoir with high salinity (249060mg/L), the single polymer HDSJ cannot continue to maintain theory viscosity value.In view of the problems of polymer degradation at high salinity, those experiences join the mass fraction of chromium acetate 2.7% with retarder, to cross-linking in a single polymer solution based on 30:1 polymer chromium rate. By testing the stability of cross-linking system, we can conclude that HDSJ gel solution with polymer chromium ratio 30:1 can meet the reservoir conditions.

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