This edition first published 2019
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Cover Images: Polymer Flooding illustration © Cyrille Cizel, Graphiste provided courtesy of Antoine Thomas
“...If you have an apple and I have an apple, and
we swap apples - we each end up with only one
apple. But if you and I have an idea and we swap
ideas - we each end up with two ideas.”
Charles F. Brannan
Polymer flooding was first applied in the early 1960s. A spurt of applications of the process occurred between 1980 and 1986, but innovation was limited because those applications were dominated by tax considerations. However, beginning with the massive Daqing polymer flood in China in 1996, polymer flooding has experienced impressive innovation and growth in field applications. The author of this book works for a company (SNF) that was instrumental in most of the important field applications of polymer flooding throughout the world. As such, SNF acquired a unique perspective on the full range of topics associated with polymer flooding. That perspective is reflected in this book – especially in the last five chapters.
There are several key challenges whose solution would greatly aid the viability of polymer flooding. First, improvements are need in our ability to distribute the energy (induced pressure gradient) from a polymer drive deep into the reservoir (where the vast majority of oil resides). To date, this issue has largely been addressed by in‐fill drilling – that is, placing injection and production wells closer together. Use of parallel horizontal wells has also been of value here. Even so, with existing polymer floods, we often must induce fractures in injection wells to allow economic injection rates for the viscous fluids. Polymer flooding could benefit greatly from improved characterization, placement, and exploitation of fractures (natural and induced) in reservoirs. This is especially true in less‐permeable reservoirs.
A second major area for improvement is reducing retention (sometimes called adsorption) of polymers by the reservoir rock. The polymer must penetrate deep into the porous rock of the reservoir in order to contact and displace the oil. If too much polymer is retained by the rock, the polymer may never penetrate sufficiently into the reservoir. Polymer retention can easily account for the largest economic hurdle in a polymer flood. In the past, laboratory studies (especially on outcrop rock) have often been overly optimistic about retention – especially in less‐permeable rock and for associative polymers. Reduced polymer retention would be of great value.
A third important challenge is in expanding polymer flooding to hotter reservoirs. Great strides have been made in identifying monomers/polymers with sufficient stability for application in these reservoirs. However, the cost and viscosity associated with these polymers are often economically prohibitive. Improved manufacturing methods may be of substantial help here.
Treatment of produced polymer fluids is a fourth critical area for improvement. The viscous nature of polymer solutions often results in produced oil/water emulsions that are difficult to separate. Produced polymer has also been tied to other production problems. New methods to address these issues are needed. An ability to recycle produced polymers would also have value. Improved sampling of produced fluids is also needed, in that knowledge of whether the polymer propagates intact through a formation provides critical guidance to the operation and expansion of a polymer flood.
This book starts at a very basic level, for those with limited prior knowledge of petroleum production. The author's goal is to provide an easy‐to‐read introduction to the area of polymer flooding to improve oil production. The book also describes polymers to improve efficiency of chemical floods (involving surfactants and alkaline solutions). Chapters are short and end with a “nutshell” summary so the reader can quickly grasp the fundamentals. Each chapter also contains key references to allow more detailed examination of individual topics. The first few chapters provide brief introductions to oil recovery, chemical flooding methods, and polymer flooding. Chapter 4 lays out the important characteristics of polymers used for polymer flooding and important tests for their evaluation. Here, it is easy to overlook a crucial contribution that was made to polymer flooding technology by polymer manufacturers. In 1986, when oil prices collapsed from ~$30/bbl to ~$16/bbl, HPAM polymers typically cost about $2/lb. Most oil companies abandoned development of enhanced oil recovery processes because the chorus of oil company managers was, “Chemical flooding for oil recovery will never be viable because the price of polymers (and other chemicals) is tied to oil prices.” However, because of innovations by polymer manufacturers, HPAM prices were commonly around $1/lb in 2012 when oil prices were over $100/bbl.
Chapters 5 through 9 provide a concise view of several key polymer‐flooding topics that can't be found elsewhere. These are in the areas of pilot project design, field project engineering (water quality, oxygen removal, polymer dissolution equipment, filtration, pumps, and other equipment), produced water treatment, economics, and some important field case histories. Overall, this book is essential reading for anyone considering implementation of a polymer flood or chemical flood.
Randy Seright
January 2018
Antoine THOMAS holds an MSc in petroleum geosciences from the Ecole Nationale Supérieure de Géologie in Nancy, France (2009). He joined SNF in 2011 as a reservoir engineer dealing with polymer flooding project design, implementation, and assistance for customers worldwide. In 2013, he spent part of his time in the R&D department, building the core flooding capacities for SNF and managing R&D projects in enhanced oil recovery (EOR) and hydraulic fracturing. He moved to Moscow in 2018 to supervise the oil and gas business from a technical standpoint, while maintaining contact with all SNF subsidiaries. He has published several papers and enjoys giving public lectures to share important learnings about EOR and hydraulic fracturing.
Thank you to all SNF reviewers and contributors who participated in the production of this book, including: Pascal Remy, René Pich, Nicolas Gaillard, Christophe Rivas, Julien Bonnier, Rémi Marchal, Flavien Gathier, Thierry Duteil, Dennis Marroni, Olivier Braun, Cédrick Favéro, Jean‐Philippe Letullier … and the list continues. A special thank you to my North American reviewing team: Ryan Wilton, Kimberley McEwen, and Matthew Hopkins. Finally, a big thank you to Cyrille Cizel for putting everything together and creating the illustrations. Tremendous work.
The energy spectrum of the world has changed dramatically over the last 100 years. Production and utilization of oil, the many offshoot industries it has spawned, and the technological advances developed have literally transformed the world as we see it today. The ubiquitous perception of abundant energy is also slowly changing, as the internet has brought information regarding the geopolitics of energy front and center.
However, have you ever asked people around you – your family, your friends, people at the fitness center – what percentage of oil can be extracted from a reservoir on average? Or, better yet, have you ever discussed with them their understanding of a geologic reservoir? You would probably be surprised to learn how many people think hydrocarbons can be recovered using a straw planted in a big, dark cavern full of oil or gas, or by shooting a bullet into the ground and having “black gold” bubble out. Moving from this fiction to reality requires education, science, time, and observation.
Moving hydrocarbons requires energy. The fossil fuels the world consumes on a daily basis are trapped in a porous material: an ancient, solid sponge formed by the accumulation of sediments over millions of years. What happens if you try to draw water from a sponge with a straw? It it slightly more difficult than simply pulling bulk fluid from a container. This same concept extends to hydrocarbon extraction.
Of the many available methods to produce hydrocarbon reserves, one involves water injection to sweep the oil toward producing wells. While widely deployed, this process (waterflooding) only helps recover approximately 35% of the oil contained in the giant “sponges.”
35%! Really? That's not much.
With 65% of the resource stranded in place, engineers and scientists have worked for decades to develop technical solutions to recover it. Enhanced oil recovery (EOR) technologies have been implemented in various fields around the world, always using a case‐by‐case approach. One such technique consists of injecting viscosified water into the formation to displace the oil, instead of regular water. The viscosity contrast between the injected water and the viscous oil creates instability and promotes water penetration through the oil or complete bypass of the oil via geological highways (i.e. where the sponge or reservoir has the largest connected pores, making the flow much more easily). Increasing the viscosity of the water through the addition of water‐soluble macromolecules (polymers) helps homogenize the displacement in the geologic formation: a larger volume of the sponge is contacted at the same time, leading to more efficient displacement and more oil being produced. This technique is called polymer flooding. It has been implemented since the late 1960s, with large commercial and technical success.
This book aims to summarize the key factors associated with polymers and polymer flooding – from the selection of the type of polymer through characterization techniques, to field design and implementation – discussing the main issues to consider when deploying this technology.
In an attempt to keep things simple, what follows is a pragmatic, rather than exhaustive, review of polymer flooding.
In terms of vocabulary, this is the last time you will read the word sponge; however, it is not the last time you will read the word viscosity!
In this chapter, the different production stages of an oil‐bearing formation will be discussed with the goal of introducing enhanced oil recovery (EOR) techniques. Mainly, this chapter will discuss the common terminology used in the industry – which divides the life cycle of an asset into three stages (primary, secondary, and tertiary production) – to show the benefits of starting EOR techniques earlier in the development phase.
The reservoir is an important component of a petroleum system. Oil and gas are formed from the decomposition of organic matter at high temperature and pressure in a source rock. Once formed, they can migrate upward until they either reach the surface and are degraded or are trapped by a seal or cap rock. If trapped, they tend to accumulate within a formation called a reservoir (Figure 1.1). Wells are drilled to reach this formation and start the extraction of the fluids.
Figure 1.1 Petroleum system and oil‐bearing reservoirs.
A reservoir can be defined as subsurface rock formation having sufficient porosity and permeability to store and transmit fluids. Sedimentary rocks are the main formations of interest since they usually have higher porosity than magmatic and metamorphic rocks. Two categories are distinguished: clastic and carbonate rocks. Clastic rocks are formed from other existing rocks after erosion, transport, sedimentation, and burial. Carbonate rocks are mainly biogenic by origin: that is, they result from the accumulation of algae or microorganism remainders.
A good conventional reservoir is one with porosity and permeability high enough to allow the fluid to flow without much additional energy other than fluid expansion, reservoir compaction, or water injection.
Much attention has recently been directed toward so‐called unconventional reservoirs, where it is necessary to adapt the technique to extract the hydrocarbons. This is the case for low permeability (tight) reservoirs or source rocks (shale gas and oil), where multi‐stage, hydraulic fracturing is required to create paths to allow for more facile fluid drainage.
Hydrocarbon production is commonly divided into three phases: primary, secondary, and tertiary (Figure 1.2).
Figure 1.2 Hydrocarbon recovery mechanisms
Primary recovery simply refers to the volume of hydrocarbons produced due to the natural energy prevailing in the reservoir or through artificial lift (i.e. pumping) through a single well. Common mechanisms behind primary recovery are as follows:
The recovery factor at the end of this stage varies greatly depending upon reservoir and fluid characteristics. It can range from 5% to 40% or more in some cases. For heavy oil reservoirs or tight formations, the value is typically on the low end of this range.
Once the natural energy has been depleted, it is necessary to add energy to maintain or increase production levels to extract the remaining reserves. Thus, the secondary stage of recovery consists of introducing additional energy into the formation via one or several injection wells to drive or sweep the remaining fluids toward production wells. This secondary recovery process typically encompasses water or gas injections or the combination of both.
In the case of water injection, two main strategies may be implemented: (i) water injection for re‐pressurizing and revitalizing the reservoir energy, and (ii) repeating pattern of injectors and producers forming a waterflood.
The tertiary or enhanced recovery stage of development can be significantly increased, reaching 50–60% for the most favorable reservoirs. However, with worldwide recovery factors averaging 35%, the study of techniques to enhance recovery of the remaining 65% left inside the formation is justified. For cases where new reservoir development is undertaken, secondary recovery could be implemented as enhanced oil recovery processes if waterflooding is forgone for transition directly to an EOR process. This could include, for example, a reservoir that is produced on primary production for a short period, after which polymer flood or cyclic steam injection is directly applied.
Between 1965 and 1979, there were five documented attempts to stimulate the production from hydrocarbon reservoirs by detonating nuclear devices in reservoir strata [1]. Three tests were performed in the United States and two in Russia, both aiming at increasing production rates and ultimate recovery from reservoirs. Subsurface explosive devices from 2.3 to 100 kt were used at depths from 1200 to 2560 m, creating post‐shot problems: formation damage, radioactivity, creation of inflammable gases, and smaller‐than‐calculated fractured zones.
Two acronyms are often encountered in the oil and gas industry when speaking about increasing the recovery of hydrocarbons: IOR for improved oil recovery and EOR for enhanced oil recovery [ 2 2 ]. IOR is a more general term, including any method toward increasing oil recovery (i.e. infill drilling, pressure support, operational and injection strategies, field redevelopment). EOR is usually considered a subset of IOR [3] and is often applied to reduce the oil saturation below the value obtained after waterflood, often referred to as the residual oil saturation (S or ) or, more specifically, residual oil saturation to waterflood (S orw ). Also, much interest has been focused on tertiary EOR. However, other definitions do not specifically tie this process to any specific production stage but rather include any method that can be used to increase the total recovery of any given field [4, 5].
The efficiency of any recovery process can be defined by how much oil is contacted and displaced in a given reservoir (Figure 1.3). Recovery efficiency, E, is characterized as the product of two terms: (i) macroscopic sweep efficiency (mobilization at the reservoir scale, EV ) and (ii) microscopic sweep efficiency (mobilization at the pore scale, ED – also known as the displacement efficiency [4]).
Figure 1.3 Areal and vertical sweep efficiency are parameters controlling oil recovery.
Macroscopic displacement efficiency relates to the volume of the reservoir contacted by the displacing fluid and is typically subdivided into areal and vertical macroscopic sweep efficiencies. This value is impacted by reservoir characteristics (geology, heterogeneities, fractures) and by fluid properties (viscosity, density). For example, it can be improved by maintaining a favorable mobility ratio between the displacing and displaced fluids by adding polymers to viscosify the injected water. This will be discussed in depth in subsequent chapters.
Microscopic displacement efficiency depends on the physical and chemical interactions that occur between the displacing fluid and oil. These include miscibility, wettability, and interfacial tension, which can be changed by adding specific additives to the injected fluid to dislodge the oil from the porous medium.
Equations (1.1) through (1.3) show the relationship and definition of all three efficiencies. ED and EV are typically expressed as fractions.
where S oi , S o , and S or are the initial oil saturation, oil saturation at time t, and residual oil saturation, respectively. Similarly, the initial and current oil formation volume factors, B oi and B o , represent the volume correction for expansion when fluids are brought to the surface. The terms Vp and Npwf refer to the pore volume (void space containing fluids) and volume of oil recovered during waterflood, respectively.
It is obviously desirable for any EOR process that the values of E D , E V and, therefore, E, are maximized. From a practical standpoint, fluids that possess the ability to enhance both microscopic and macroscopic sweep efficiencies are difficult to develop. Many hurdles can be faced in developing and implementing such a fluid, including the following:
The choice of the most suitable EOR method requires an upfront clarification of expectations. Given the many uncertainties encountered throughout the process, it is illusory to expect a perfect EOR fluid formulation. De‐risking can be achieved step‐by‐step through pilot tests and pragmatic approaches aimed at solving one problem at a time. A pilot project will be a critical step before considering full‐field development.
EOR methods can be classified in several categories whose exact number depends on the authors and criteria. Green and Willhite [4] considered five categories (mobility‐control, chemical, miscible, thermal, and other processes such as microbial EOR), while Lake [5] described three main subdivisions (thermal, chemical, and solvent methods). A good compromise would be four categories with thermal, chemical, miscible, and other EOR methods (microbial). Although this book is exclusively devoted to chemical methods and polymer flooding in particular, a brief description of each recovery technique will be given next.
Thermal processes include hot water injection, steam injection, and in situ combustion. Steam is used in two different ways: cyclic steam stimulation (CSS, Figure 1.4) or steam flood (Figure 1.5). Oil production is increased mainly due to thermal heat transfer, resulting in several mechanisms including oil viscosity reduction, oil swelling, and steam flashing.
Figure 1.4 Cyclic steam stimulation.
Figure 1.5 Steam flood process
For in situ combustion processes (Figure 1.6), air injection is implemented to generate thermal energy within the reservoir, and oil is recovered via viscosity reduction, fluid vaporization (light‐end solvents, CO2), or thermal cracking [6].
Figure 1.6 In situ combustion process.
This category includes the injection of water‐soluble polymers, surfactants, and alkali alone or in combination, as well as other chemical cocktails such as microgels and nanogels, aimed at improving oil recovery from a given reservoir via conformance control. Polymers are used to viscosify the injection water and improve the overall sweep efficiency, E. Surfactants (surface active agents) are designed to lower the interfacial tension (IFT) between oil and water, mobilizing capillary‐trapped oil. Alkali is used to synergistically improve the efficiency of surfactants via several mechanisms that will not be described in this section.
Microgels and nanogels are chemical technologies containing small polymer particles whose main goal is to decrease the permeability of thief zones, diverting the water to previously unswept areas. Their design and use is complex and requires a good reservoir understanding.
The objective here is to displace the oil with a fluid that is miscible in it, forming a single phase that can be moved through the reservoir (Figure 1.7). Green and Willhite [4] describe two categories:
Figure 1.7 CO2 miscible process.
Screening criteria for the applicability of each method will not be discussed here. References are given at the end of the chapter for further reading.
The budgets assigned to EOR developments often compete with other expenses, especially in terms of capital required for exploration (looking for undiscovered fields), new infill drills, injector conversions, maintenance programs (pump replacements, workovers) etc. However, several factors must be considered when evaluating EOR techniques against other development options [3]:
The benefit of any EOR technique is that it applies to every brownfield because:
As with greenfield developments, the objective is to maximize the final recovery from the outset of the development, knowing the current limits of secondary recovery techniques. Experience has shown that more than 60% of oil remains trapped in reservoirs after water injection. Why wait for production to become uneconomical before considering the so‐called tertiary methods? Evaluations to collect the necessary data to model and appropriately de‐risk the investment require time to implement and therefore should be started as early as possible. EOR techniques allow for accelerated oil production: the return on investment is quicker, which is beneficial when the time to exploit concessions is short.
