The Impact of EOR Polymers on Scale Inhibitor Adsorption

2020 ◽  
Author(s):  
Alan Beteta ◽  
Katherine McIver ◽  
Oscar Vazquez ◽  
Lorraine Boak ◽  
Myles Jordan ◽  
...  
Keyword(s):  
Scale Inhibitor ◽  
The Impact

Correlation of Shear and Turbulence on Scale Formation and Inhibition

2014 ◽  
Author(s):  
Gordon M. Graham ◽  
Hunter Thomson ◽  
Deborah Bowering ◽  
Robert Stalker
Keyword(s):  
Jet Impingement ◽  
Flow Regimes ◽  
Test Methods ◽  
Bulk Liquid ◽  
Shear Stresses ◽  
Scale Inhibitor ◽  
Static Tests ◽  
Brine Chemistry ◽  
The Impact ◽  
Production Conditions

Abstract Current scale risk analysis focuses on thermodynamic calculations to determine the risk of scale, ignoring system kinetics and the impact of flow regimes on scale precipitation from mildly oversaturated systems. It is however recognised that flow regimes affect scale precipitation. Surface growth is influenced by mass transport and diffusion which are susceptible to shear stress and turbulence. Little work has been reported which examine these factors under conditions that can be readily tuned to match field production conditions. Scale inhibitor evaluation exercises therefore often rely on conventional low shear/static or laminar flow conditions which have been demonstrated in many papers to be largely inadequate for mildly oversaturated systems. This work addresses this concept and focuses on scale deposition and growth at metal surfaces as well as bulk (liquid phase) nucleation and growth in mildly oversaturated brines as a function of increasing shear. A series of controlled experiments have been conducted under “mildly oversaturated” conditions to examine the effect of; no shear conventional “static” tests, moderate shear mixed statics and much higher shear regimes including rotating cage and jet impingement approaches with calculated shear stresses up to 500 Pa and higher. This builds on previous work published by the authors in this area1 and further illustrates the importance of conducting tests at field representative shear conditions. Since shear and turbulence have a governing effect on the critical scaling tendency (the level of oversaturation below which brines remain stable under normal production conditions) the ability to correlate between shear and the propensity for scaling in mildly oversaturated systems is critically important in determining the risk of scale at different locations in the production stream. New test methods have been validated which allow the impact of shear and turbulence to be observed under conditions more representative of production conditions. These methodologies lead to scaling in mildly oversaturated brine systems without having to adjust brine chemistry or otherwise increase the scaling regime, i.e. by adjusting the flow regime to reproduce the shear expected at critical locations in the production system. Improved methodologies are therefore presented which allow more appropriate scale inhibitor qualification, taking into account the impact of shear and turbulence under field representative conditions. The work shows that this is critically important for mildly oversaturated conditions.

The Impact of Pre-flush Additives on Scale Squeeze Treatments - Application of Modelling and New Test Methodologies to Understand Mechanisms of Retention and Optimise Field Treatment Designs

2014 ◽  
Author(s):  
O.. Vazquez ◽  
T.. Chen ◽  
L.. Crombie ◽  
P.. Chen ◽  
S.. Heath ◽  
...  
Keyword(s):  
Computer Modelling ◽  
Scale Inhibitor ◽  
Retention Mechanisms ◽  
Test Methodology ◽  
Production Stages ◽  
Modelling Techniques ◽  
Treatment Designs ◽  
The Impact ◽  
Scale Deposition ◽  
Modelling Data

Abstract One of the most common methods to prevent scale deposition in the near wellbore area is through the application of squeeze treatments which conventionally consist of pre-flush, main treatment, overflush, shut-in and back production stages. The use of additives such as polyamino acids and polyquaternary amines has often been successfully applied as part of the pre-flush stage of squeeze treatments to improve treatment lifetimes (Chen et al., 2006, Vazquez et al., 2011, Heat et al., 2012). However, although this technology has been successful applied in the field, there is still a lack of understanding of the prevalent retention mechanisms with different scale inhibitors and also a suitable test methodology and modelling techniques to optimize field treatment designs and lifetimes. A new sand pack methodology which provides a better simulation of field squeeze treatments than traditional corefloods has been designed to provide a better understanding of the scale inhibitor retention mechanisms when polyquaternary amines are applied in pre-flush treatments. This has enabled improved treatment modelling and the impact of these additives to be understood in field treatments. The performance of the polyquaternary amine is dependent upon scale inhibitor chemistry and the mechanisms of retention are addressed for both polymeric and phosphonate scale inhibitors. The adsorption isotherms were derived and compared in the absence/presence of the polyquaternary amine using specialized software, and applied to predict squeeze lifetime in field scenarios. This paper provides an understanding on the effects of polyquaternary amines on squeeze lifetime for both phosphonate and polymeric scale inhibitors supported by the application of a newly developed test methodology and computer modelling techniques. In addition, the combination of laboratory and computer modelling data coupled with field experience and a better understanding of the retention mechanisms involved now provides the ability to improve and optimize field squeeze treatment designs with polyquaternary amine pre-flush additives.

Laboratory Evaluation and Mechanistic Understanding of the Impact of Ferric Species on Oilfield Scale Inhibitor Performance

2018 ◽  
Vol 32 (8) ◽  
pp. 8348-8357 ◽  
Author(s):  
Zhang Zhang ◽  
Ping Zhang ◽  
Zhejun Li ◽  
Amy T. Kan ◽  
Mason B. Tomson
Keyword(s):  
Laboratory Evaluation ◽  
Scale Inhibitor ◽  
Mechanistic Understanding ◽  
The Impact

The Impact of Organic Acid on Scale Inhibitor/Corrosion Inhibitor Interaction, a Case Study from West Africa

2011 ◽  
Author(s):  
Kevin Spicka ◽  
Clare Jennifer Johnston ◽  
Myles Martin Jordan ◽  
Lisa Nguyen ◽  
Sandra Linares-Samaniego ◽  
...  
Keyword(s):  
West Africa ◽  
Organic Acid ◽  
Corrosion Inhibitor ◽  
Scale Inhibitor ◽  
The Impact ◽  
Inhibitor Interaction

How Does EOR Polymer Impact Scale Control During ASP Flooding?

2021 ◽  
Author(s):  
Ya Liu ◽  
Rebecca Vilain ◽  
Dong Shen
Keyword(s):  
Oil Recovery ◽  
Synergistic Effects ◽  
Oil And Gas Industry ◽  
Scale Formation ◽  
Test Method ◽  
Scale Inhibitor ◽  
Acrylic Copolymer ◽  
Asp Flooding ◽  
Bottle Test ◽  
The Impact

Abstract Polymer based enhanced oil recovery (EOR) technology has drawn more and more attention in the oil and gas industry. The impacts of EOR polymer on scale formation and control are not well known yet. This research investigated the impacts of EOR polymer on calcite scale formation with and without the presence of scale inhibitors. Seven different types of scale inhibitors were tested, including four different phosphonate inhibitors and three different polymeric inhibitors. Test brines included severe and moderate calcite scaling brines. The severe calcite brine is to simulate alkaline surfactant polymer (ASP) flooding conditions with high pH and high carbonate concentration. The test method used was the 24 hours static bottle test. Visual observation and the residual calcium (Ca2+) concentration determination were conducted after bottle test finished. It was found that EOR polymer can serve as a scale inhibitor in moderate calcite scaling brines, although the required dosage was significantly higher than common scale inhibitors. Strong synergistic effects were observed between EOR polymer and phosphonate scale inhibitors on calcite control, which can significantly reduce scale inhibitor dosage and provides a solution for calcite control in ASP flooding. The impact of EOR polymer on polymeric scale inhibitors varied depending on polymer types. Antagonism was observed between EOR polymer and sulfonated copolymer inhibitor, while there was weak synergism between EOR polymer and acrylic copolymer inhibitors. Therefore, when selecting scale inhibitors for polymer flooding wells in the future, the impact of EOR polymer on scale inhibitor performance should be considered.

Improving Scale Inhibitor Squeeze Design for Naturally Fractured Reservoirs

2014 ◽  
Author(s):  
Victoria E Spooner ◽  
Robert Stalker ◽  
Rob Wright ◽  
Gordon M Graham
Keyword(s):  
Fractured Reservoirs ◽  
Injection Rate ◽  
Release Mechanism ◽  
Transport Mechanisms ◽  
Scale Inhibitor ◽  
Diffusion Controlled ◽  
Matrix Flow ◽  
Fractured Well ◽  
The Impact ◽  
Treatment Design

Abstract Scale Inhibitor (SI) squeeze treatments continue to be an important method for delivering chemical to the production system. However, while SI squeeze treatments in unfractured reservoirs can generally be readily simulated in matrix flow models, designing such treatments for application in fractured reservoirs is less routine, and resulting field treatment lifetimes can be disappointing. One reason for this is that the flow process and transport mechanisms by which the inhibitors are retained in fractured formations differs considerably from simple matrix flow. In this paper we expand upon previously published work examining the impact of squeeze treatment design on the outcome of a SI squeeze treatment for a fractured well using a novel fractured well squeeze model. In previous papers, we highlighted the importance of diffusion-controlled transport of SI in low permeability tight matrix fractured reservoirs where little matrix flow is possible. In this paper, we report continuing developments of the fracture squeeze model and demonstrate how differences between advection and diffusion-controlled inhibitor transport can significantly alter the predicted squeeze treatment lifetimes, and suggest appropriate treatment design modifications to improve SI squeeze treatments in such fractured reservoirs. This paper will demonstrate that such differences in transport mechanisms directly impacts the distribution of scale inhibitor within the near-wellbore region during the treatment phase. In fractured systems, this SI distribution is affected both by the extent of propagation of injection fluid through the fracture network and rate of diffusion into the surrounding matrix rock. This work examines the influence of factors such as injection rate, soak time, inhibitor diffusivity and retention/release properties on the matrix material. By adjusting injection parameters such as injection rate and soak time in the treatment design, a more desirable distribution of scale inhibitor can be obtained, resulting in improved predicted treatment lifetimes. Thus, using the fracture squeeze model to provide a fuller simulation of the inhibitor transport, retention and release mechanism active in a fractured reservoir, we highlight potential placement issues for such reservoirs and demonstrate methods to improve squeeze design for fractured wells.

The Influence of Turbulence (or Hydrodynamic Effects) on Strontium Sulphate Scale Formation and Inhibitor Performance

2014 ◽  
Author(s):  
Clare Johnston ◽  
Louise Sutherland
Keyword(s):  
Barium Sulphate ◽  
Test Methods ◽  
Standard Test ◽  
Field Application ◽  
Scale Formation ◽  
Test Method ◽  
Scale Inhibitor ◽  
Modified Method ◽  
Bottle Test ◽  
The Impact

Abstract Inorganic scale (carbonate, sulphate and sulphides) formation can be predicted from thermodynamic models and over recent years better kinetic data has improved the prediction of such scales in field conditions. However these models have not been able to predict the observed deposition where flow disturbances occur, such as at chokes, tubing joints, gas lift valves and safety valves. This can lead to unexpected failures of critical equipment such as downhole safety valves (DHSV’s), and operational issues such as failure to access the well for coiled tubing operations due to tubing restrictions. In recent years it has been recognised that the turbulence found at these locations increases the likelihood of scale formation and experiments have been able to demonstrate that increased turbulence also impacts the minimum scale inhibitor concentration required to prevent scale. One of the industry standard test methods used to screen inhibitors for sulphate scale inhibition is the static bottle test. In this paper the ‘static’ bottle test method is modified to investigate the effects of increasing levels of turbulence on the formation of strontium sulphate scale at a fixed brine composition. Using this modified method it has been possible to demonstrate the impact of varying turbulence on the performance of two common generic types of scale inhibitor (phosphonate and vinyl sulphonate co-polymer). Data on the mass of scale formed, scale morphology using SEM imaging and inhibitor efficiency will be linked to degree of turbulence and scale inhibitor functionality (nucleation inhibition vs. crystal growth retardation). This study builds on the previously published10 findings for barium sulphate which showed phosphonates were less affected by turbulent conditions by carrying out similar tests on strontium sulphate. A clear mechanistic conclusion can now be drawn for sulphate scale formation and inhibition under increasingly turbulent conditions. The findings from this study have a significant impact on the methods of screening scale inhibitors for field application that should be utilised and development of suitable inhibitors that perform better under higher shear conditions.

The Evolution of CaCO3 Scaling Potential in ADNOC Reservoirs Under Water Flooding and CO2 WAG Scenarios

2021 ◽  
Author(s):  
Giulia Ness ◽  
Kenneth Stuart Sorbie ◽  
Ali Hassan Al Mesmari ◽  
Shehadeh Masalmeh
Keyword(s):  
Pressure Drop ◽  
Co2 Concentration ◽  
Water Flooding ◽  
Operating Pressure ◽  
Scale Inhibitor ◽  
Stock Tank ◽  
Wellbore Pressure ◽  
Scaling Potential ◽  
Water Cut ◽  
The Impact

Abstract Wells producing from an oilfield in Abu Dhabi were investigated to understand the CaCO3 scaling risk at current production conditions, and to predict how the downhole and topside scaling potential will change during a planned CO2 WAG project. The results of this study will be used to design the correct scale inhibitor treatment for each production phase. A rigorous scale prediction procedure for pH dependent scales previously published by the authors was applied using a commercial integrated PVT and aqueous modelling software package to produce scale prediction profiles through the system. This procedure was applied to run many sensitivity studies and determine the impact of field data variables on the final scale predictions. These results were used to examine the scaling potential of current and future fluids by creating a diagnostic "what if" chart. Some of the main variables investigated include changes in operating pressure, CO2 and H2S concentrations and variable water cut. Scale prediction profiles through the entire system from reservoir to stock tank conditions were obtained using the above modelling procedure. The main findings in this study are: (i) That CaCO3 scale is not predicted to form at separator conditions under any of the current or future scenarios investigated for these wells. This is due to the high separator pressure which holds enough CO2 in solution to keep the pH low and prevent scale precipitation. (ii) The water at stock tank conditions was found to be the critical point in the system where the CaCO3 scaling risk is severe, and where preventative action must be taken. (iii) Implementing CO2 WAG does not affect CaCO3 scaling risk at separator conditions where fluids remain undersaturated. However, the additional CO2 dissolves more CaCO3 rock in the reservoir producing higher alkalinity fluids which result in more CaCO3 scale precipitation at stock tank conditions. (iv) Fluids entering the wellbore are likely to precipitate some CaCO3 (albeit at a fairly low saturation ratio, SR) due to a significant pressure drop and the relatively high temperature, and this is not associated with the-bubble point in this case. This downhole scaling potential becomes slightly worse by an increase in CO2 concentration during CO2 WAG operations.(v) Scale inhibitor may or may not be required to treat downhole fluids depending on the wellbore pressure drop, but it is always necessary to treat fluids downstream of the separator due to the very high scaling potential at stock tank conditions. By applying a rigorous scale prediction procedure, it was possible to study the impact of CO2 WAG on the risk of CaCO3 scale precipitation downhole and topside for this field. These results highlight the current threat downhole and at stock tank conditions in particular and show how this will worsen with the implementation of CO2 WAG and this will require a chemical treatment review.

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