From Mineral Surfaces and Coreflood Experiments to Reservoir

Subscriber access provided by READING UNIV

Review

From Mineral Surfaces and Coreflood Experiments to Reservoir Implementations: Comprehensive Review of Low Salinity Water Flooding (LSWF) Dayo Afekare, and Mileva Radonjic Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b02730 • Publication Date (Web): 20 Nov 2017 Downloaded from http://pubs.acs.org on November 21, 2017

Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a free service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are accessible to all readers and citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.

Energy & Fuels is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.

Page 1 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

From Mineral Surfaces and Coreflood Experiments to Reservoir Implementations: Comprehensive Review of Low Salinity Water Flooding (LSWF) Dayo A. Afekare* and Mileva Radonjic Craft and Hawkins Department of Petroleum Engineering, Louisiana State University, Baton Rouge, 70803, United States Keywords Salinity, wettability, hydrocarbon recovery, relative permeability, coreflood, simulation, mineral surfaces, zeta-potential, EOR, CCS

ABSTRACT: Low salinity water flooding (LSWF) is an emerging and inexpensive enhanced oil recovery (EOR) method. The technique hinges on the following concept: as salinity of injected water reduces, additional oil is recovered. However, LSWF remains emerging because its underlying mechanisms have been largely elusive - and the identified ones have been controversial. If properly investigated, smart water injection may contribute to harnessing both heavy oil reservoirs - which account for nearly 80% of world’s petroleum reserves –

and

conventional light-to-medium oil reservoirs. 1 ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 2 of 74

This report presents a comprehensive review of Low salt water injection as an EOR method, with a specific focus on consistencies or lack of them, that occur primarily due to inadequate understanding of oil/brine and rock/oil/brine interactions. In presenting well-documented scientific information, we expect to apprise industry and academic researchers that LSWF warrant more advanced research based on interdisciplinary approach (bridging gap between science and engineering) and integration of knowledge from R&D efforts and observations from atomic to field scales.

1. INTRODUCTION Two-thirds of oil and gas reserves in the world are carbonates, and the remaining are sandstones. Also, heavy oil accounts for up to 80% petroleum reservoirs worldwide, but high asphaltene contents, high viscosity and low API have left majority of these deposits buried in the ground. Conventional light-to-medium oil reservoirs have suffered substantial depletion since oil exploration began, thus demanding efficient and economic post-primary recovery techniques. Further, it has been estimated that initial available energy of most reservoirs can only yield about 30% recovery, which means secondary and tertiary recovery techniques will be always be in demand. Water flooding, the most economical secondary recovery process, has been widely deployed to nearly 60% of heavy oil fields and more for conventional reservoirs using produced water. Majority of oil and gas producing reservoirs contain far more water than petroleum; on average, 10 barrels of water are produced per barrel of oil in the U.S.

1

According to a 2007 report by

Argonne National Laboratory (monitored by U.S. Department of Energy), an average of 74.4 million bbl/day water was produced from close to 1 million producing oil and gas wells in the U. S.

1

Of course, these colossal volumes are often under-utilized, more so that they are usually 2 ACS Paragon Plus Environment

Page 3 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

contaminated and will have to be treated for industrial and/or residential usage. Water-in oil emulsions causes huge damage to aquatic environment. Fresh water which would have been preferred is increasingly becoming scarce. In the US. Alone, National Renewable Energy Laboratory (NETL) states that electricity production requires 190,000 gallons of water per day, which is roughly 39 per cent of all freshwater withdrawals.2 Therefore, it has now become more imperative than ever before to devise cost-effective means of harnessing effluent water resources in the Oil Industry. In addition, the economics of waterflooding has drawn attention of researchers to make advances for improvement by examining interconnection of water viscosity, density and chemical composition to that of oil and surrounding rock formation i.e. rock/oil/brine interactions. Recently, one such property of interest is brine salinity.

LSWF, otherwise called smart water flooding, is yet to be a generally established EOR technique primarily because the mechanisms have been not being fully understood. In simple terms, no dominant mechanism(s) underlying smart water flooding has been identified. Many researchers have established that, while formation water salinity may range from 50,000ppm and above, injected water salinity must be as low as between 1,500ppm-5,000ppm for any effect - otherwise called Low salinity effect (LSE) - to be apparent. This range, they conclude, varies with formation brine salinity, brine composition, rock mineralogy and so on. An optimum salinity level of 1,500ppm has been declared, below which no additional oil is produced

3-5

Refreshing also,

desalination of produced water (using Reverse Osmosis) and subsequent re-injection are potentially cheaper than transportation and disposal of produced brines. In 2014, Advanced Resource International 6, estimated desalination cost to be 0.2-0.6 USD/bbl whereas disposal cost

3 ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 4 of 74

may be as high as 8 USD/bbl. In addition, transportation to disposal sites may cost between 2-6 USD/bbl.6, 7

This paper starts with discussion of key findings concerning low salinity water injection from research performed since the 1940s8 up until recent time.9 Section 2 provides a view of how LSWF should be systematically investigated from micro to macro-scale investigations with few examples from literature. Section 3 discusses mechanistic studies on LSWF: clear description of multiple case studies under different smart water injection mechanisms and also how reservoir simulation studies have demonstrated Low salinity effects. Section 4 presents results on actual field observations: log-inject-log, SWCTT and pilot tests. Section 5 makes an overview discussion of evolution of research effort over the years, significance of already identified mechanisms in recovery efficiency and key insights based on entire review. Column charts showing incremental recovery results reported from coreflooding and compositional reservoir simulation across different reservoirs are presented. Interesting statistical and quantitative analyses on conditions and mechanisms underlying LSWF are made. Developing insights which include representative contact angle studies, impact of pore roughness, use of natural in-situ Low salt brines among others are introduced. Section 6 concludes the report with main highlights and critical recommendations.

2. SYSTEMATIC INVESTIGATION Reservoir rocks – be it sandstone, dolomite or limestone - are usually large-scale formations (from hundreds of thousands to million sq.m.) which may contain millions of barrels of oil and water. However, these large subsurface rock volumes contain infinite tortuous channels, often micrometer width, containing chemically complex fluids within highly varied mineralogical composition. To gain complete knowledge and make reliable prediction of subsurface processes, 4 ACS Paragon Plus Environment

Page 5 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

water chemistry, oil composition, mineral composition and rock porous structure must first be analyzed at nano- and micro-levels. Mechanisms and integrated effects of observed properties can then be further examined in a more magnified view at macro-scale level, which may be: reservoir simulation, log-inject-log test or even field implementation. In other words, systematic investigation of LSWF may begin from atomic scale through Atomic Force Microscopy (AFM) and electrokinetic analyses i.e. Zeta potential at nanometric levels to corefloods and up to compositional reservoir simulation, as shown in Figures below. Indeed, these different areas of investigation have been examined with some areas receiving more attention than others.3, 10-13

Zeta potential can be used to analyze stability of colloidal dispersion through electrokinetics10, 14

and electroacoustic phenomena.15 Atomic Force Microscopy has been used both recently16 and

in the past17 , and data interpretation does require deep understanding of particle physics and colloidal chemistry to explain LSE. However, this cutting-edge approach has only received little attention both in the past and present. Coreflooding, micromodelling and spontaneous imbibition experiments have been performed by numerous researchers, and in most cases, have shown encouraging results in terms of crude oil behavior in response to LSWF. At field scale, Reservoir Simulation, Log-Inject-Log Tests, SWCTT and other field trials have demonstrated that recovery efficiency and residual saturation can be improved. Again, as expected, reservoir simulation being the most economic macroscale method, have been performed more frequently overall.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 6 of 74

LSWF Distinctive Study

Micro-scale investigations (oil/brine interactions, rock/oil/brine interactions)

Micromodellin g (μm to mm)

Coreflooding (mm to cm)

Zeta Potential (μm to mm)

Figure I.

Contact angle (μm to mm)

Macro-scale investigations (rock/oil/brine interactions)

Reservoir simulation (km)

Log-Inject-Log Test (feet)

Spontaneous imbibition (mm to cm)

SWCTT (feet)

Field implementation (km)

Process flow chart illustrating systematic investigation of LSWF. The length scale

of investigation is stated in brackets.


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Sequence of research procedure

Page 7 of 74

Geochemical simulation

Reservoir scale ( km to )

Coreflooding experiments

Core scale ( cm to m) Pore-network scale ( μm to mm)

Micromodelling

Atomic Force Microscopy/Zeta Potential Analyses

Atomic scale (nm to μm)

Figure II. An illustration of Systematic investigation of LSWF: at atomic scale we can delineate mechanisms that occur at mineral surfaces; next step is observation of multi-fluid flow patterns through complex rock-like porous media structure; the real rock core samples flooded by reservoir fluids subsequently displaced by LSWF at reservoir Temperature & Pressure are the most realistic lab experiments, but lack detail; finally reservoir modeling is capable of multiple physical scenarios under extended periods of time, predicting real-world applications, whose realism is based on verification from adequate reservoir characterization, field data and/or time resolved experiments. It is interesting to note that, the scale of investigation determines what effects are being observed. At small scales, experiments typically investigate crude oil and water droplets flowing through or occupying pore spaces in the order of nm to micro-m. In LSWF studies, AFM can and has been used to investigate surface charges and surface forces such as Van Der Waal, Debye interaction, 7 ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 8 of 74

adhesion of polar and non-polar oil compounds and hydrophobic interactions.16 Zeta potential, which is a measure of stability of dispersion in particle suspension and liquid emulsions, can investigate electrokinetic effects, double layer expansion, colloidal stability, solid-liquid interfaces. 18, 19 Moving to micrometre scale, micromodelling experiments are useful to examine oil/brine interactions 20-24, foam/oil interactions25, porous media flow26, 27 and in some cases fines migration .

28

These may involve change in salinity gradient in the presence of an oleic phase,

known as osmosis29 or the formation and subsequent migration of oil-in-water emulsions from bulk phase to oil-water interface.

9

Pore-scale fluid distribution, water-in-oil emulsions and

saturation changes during EOR flooding experiments are some important phenomena which can be imaged with Computed Tomography.30, 31

Up to centimeter scale, coreflooding experiments has the capacity to examine crude oil/rock/brine (COBR) systems. Likewise, spontaneous imbibition is a well-established technique of investigating rock/fluid interactions 9, fluid/fluid interactions32 and wettability studies.33 At this scale, migration of clays and subsequent permeability damage may be investigated during LSWF, shown in early works.

3, 8, 34-37

Ultimately, recovery efficiency, relative permeability and fluid

saturation are inferred or measured from core flow-through experiments, as the key parameters required in building representative reservoir models.

Finally, since reservoir simulation usually constitute results that are central to field implementation projects, pressure drop, water cut, injection and production rates are parameters of primary concern, in addition to recovery factor and saturation. 38-40 Thus, focus on mechanisms of LSWF during nano- and micro-scale investigations translate into petrophysics at medium scale


Page 9 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

and, consequently reservoir engineering becomes more effective at larger length scale due to understanding of the processes at the atomic scale. Table I presents affiliated test, investigation scale, examinable effects and obtainable parameters from oil/brine and crude oil/brine/rock interactions. It should be mentioned that the tests presented in this table are not limited to listed parameters and effects.

Table I.

Comprehensive description of oil/brine and COBR system of interactions: Tests,

Scale of investigation, Examinable effects and Obtainable parameters Scale investigation (unit)

System of interactions Tests

Atomic Microscopy

Å - nm

Zeta potential

Obtainable Parameters

µm

osmotic potential, micro dispersion formation, fines migration

Recovery efficiency, Fluid saturation using binary segmentation

µm

wettability changes, crude oil desorption, interfacial tension changes

Contact angle, Capillary pressure, interfacial tension

Oil/brine

Contact measurements

Examinable Effects

Debye Interactions, rock surface charges, surface forces, adhesion of crude oil compounds, Debye Length, hydrophobic Surface Charges, interactions Adhesion Force

Force

Micromodelling

of

angle

nm to m

Electrokinetic Zeta potential, effects, Double pH, ionic Layer Expansion strength (DLE), film 9

ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 10 of 74

stability, exchange

Core floods

Spontaneous imbibition

mm to cm

mm to cm

Wettability change in fluid index, Fluid saturation, saturation, wettability Relative modification permeability

nm to m

Electrokinetic effects, EDL, colloidal stability, rock/fluid Zeta potential, interfaces, film pH, ionic stability strength

Micro-Computed Tomography (Micro-CT) Scan imaging Environmental Scanning Electron Microscope (ESEM) imaging X-Ray Diffraction (XRD) Crystal analysis related

Reservoir Simulation

Recovery efficiency, effluent ion concentrations, Fluid saturation, Pressure drop, Absolute Permeability, Relative permeability

fines migration, permeability damage, crude oil adsorption, ion exchange, wettability modification

Crude Oil/Brine/R ock Zeta potential

ion

km

m

change in mineralogical CT number, structure Penetration time

m

Mineralogical impact of LSWF content, pore on rock size, pore throat morphology size size

Mineralogical content variation in pressure drop, salinity, areal water cut, sweep recovery factor, efficiency, ion injection and exchange, production rates pressure


Page 11 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

response, flooding cycle

3. MECHANISTIC STUDIES The feasibility of reduced salinity injection lies in the prominence of certain environments and mechanisms which can be investigated from different approaches. This section of the report deals with the understanding of key conditions and mechanisms supporting the success of smart water flooding.

3.1

Necessary Conditions for improvement of recovery efficiency through LSWF

It has been proven that for low salt water injection to influence reservoir efficiency, some necessary initial conditions are required, some of which are: presence of clay, mixed wetness, presence of polar oil components and presence of active cations in formation water. 41

3.1.1

Clay presence

The presence of clay – especially kaolinite - is a crucial condition for low salinity water flooding to be effective as an EOR method. This is because clay is naturally reactive, with its negatively charged sites easily binding with either cations from existing connate brine or newly injected sea water, while its positive sites are bounded to carboxylic groups (polar components). Clay affinity series explains why certain ions have an established order of clay affinity, which hypothetically explains the ion exchange processes in the presence of two or more of these ions as part of rock/brine interactions. As low salt water is injected, ion exchange takes place at clay surfaces, in which bound ions are detached from these surfaces, thus triggering release of clay particles. The release and subsequent transport of these particles is referred to as fines migration, and as proven 11 ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 12 of 74

by some researchers, has been advantageous in improving recovery factor via LSWF. 3, 8, 12, 34-37, 42-44

3.1.2

Mixed wetness

Mixed wetness refers to a wettability state of a reservoir in which parts of the formation preferentially contact water while other parts contact oil. Geological history backs this phenomenon, as oil migrated, it displaces water – but not in all parts of a given reservoir - by capillary, gravity and viscous effects. Early studies reveal the occurrence of non-water wet reservoirs. Treiber and Owens

45

reports that 40 of 55 reservoirs (30 sandstone and 25 carbonate

reservoirs) are not water wet. Morrow 45

46

re-evaluated the same reservoirs as Treiber and Owens

and discovered 41 of these reservoirs to be either oil- or intermediate-wet. Of 121 carbonate

samples with which Chilingar and Yen 47 performed experiments, only 8% were found to be water wet. These inferences may have been partially influenced by different contact angle cut-offs used, but this clearly shows that oil-wet and intermediate-wet reservoirs do exist. Indeed, different parts of a reservoir may be hydrophilic or hydrophobic, depending on saturation history and pore size distribution. Subsequent transport of certain adsorbable polar oil components like resins and aromatics may establish oil-wetness or in a more realistic state mixed wetness.

Low salinity flooding is believed to improve wettability of a formation from mixed to water wet. Since wettability controls how formation fluids are distributed through the infinite reservoir pore networks, mixed wetness should amplify effect of LSWF in oil recovery. To add, wettability improves, adhesion force between oil and rock reduces, existing trapped oil are mobilized and


Page 13 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

more oil is produced, as an AFM study have shown. 16 Hence, having a mixed-wet state which can be improved by injection of low salt water is important.

3.1.3

Presence of polar components

Crude oil usually contains acids and bases components from asphaltenes and fatty acids respectively, which are crucial for wettability changes. Longer chain hydrocarbon fractions have also been declared prominent in altering the preference of a rock to contact water in the presence of oil, forming rigid films on pore surfaces. However, not all crude components are influential in this regard. An attempt by Cuiec

48

to examine correlation between rock/oil interaction and

wettability reveals that low boiling point (< 350C) and low molecular weight (300-350g/gmol) fractions had no effect on surface properties of rocks. Whereas, in the same vein, it was discovered that asphaltene, sulphur, aromatics and resins, are retained on the rock surfaces and thus easily alter wettability towards oil wetness. Ehrlich

49

conducted an experiment which shows that acid

fractions did not affect wettability of Berea sandstone cores, yet Strassner 50 stated that wetting of glass by crude oil may be enhanced through basic nitrogen-containing groups. When Basu and Sharma 17 exploited AFM to determine the role of asphaltenes and resins in wettability study, they observed that these polar components altered wettability of a glass substrate towards oil wetness. Lowe et al.

51

maintains that acid substances in crude attach to carbonate surfaces and form a

film through chemisorption (an adsorption which involves adsorbate reacting with surface). Madsen and Ida 52 discovered that heavy crude fractions which distill between 370 and 450C are responsible for changing wettability of Bradford reservoir. Johansen and Dunning

53

while

conducting an experiment on effect of hydrocarbon chains on wettability studies demonstrated that propane precipitates from Rio Bravo, Tatums and Bartlesvile promoted oil wetness of glass 13 ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

surface. Shehata and Nasr-El-Din

54

Page 14 of 74

maintains that polar crude components (asphaltenes and

resins) can either adsorb directly onto charged clay surfaces or multivalent cations can bind polar components to mineral surfaces. As low salt water is injected, these components tend to repel further from clay surfaces, which leads to oil desorption and improvement of oil recovery. In crude oil samples, polar components have been shown to be useful in low salinity flooding as they partake in the brine/oil/rock interactions which reduces residual oil saturation and in turn increases ultimate recovery. 55, 56

Having discussed necessary conditions, selected key mechanisms identified in literature are presented below.


Page 15 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

3.2 Key mechanisms underlying LSWF 3.2.1

Fines Migration and Permeability Reduction

Over millions of years, clay particles form as end products of mineral weathering, and eventually get attached to mineral surface within the pores or fill in intergranular rock space forming thin heterogenous layers in sandstones or thick layers of cap rock shale. According to Baptist

34,

clays are hydrated to a certain degree and swell water at the time oil fields are

discovered. Initially, the clay particles are predominantly negatively charged while the majority of other mineral surfaces are positively charged. It should be said that owing to its function group (COO-), crude oil is primarily negatively charged while formation brine is positively charged (focus being on cations). Tang and Morrow 3 explained LSWF effects by ascribing it to fines migration. Akhmetgareev and Khisamov 37 used moment of balances to describe the relationship between release of clay particles and salinity.

A review of both shows that LSWF causes reduction in electrostatic force since clay act as a cation exchanger. Consequently, the moment of balance is distorted; clay and silt are detached from the rock surface and dispersed into the formation. These mobile particles flow into porous medium and become trapped in small pores resulting in permeability reduction – an observation of Johnston and Beeson. 8 On the long run, water finds the less resistant paths for flow and thus recovery is improved. This hypothesis implies that clay migration and permeability reduction mechanisms under LSWF have so far been inseparable. Akhmetgareev and Khisamov

37

proposed a model to state the relationship between permeability and quantity of “strained fines” in an effort to correlate clay presence with rock permeability. Spontaneous imbibition experiment also proved increase in oil recovery with decrease in salinity for different sandstone (Berea sandstone) cores, hence underlining the importance of fines migration.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 16 of 74

However, some cases report LSWF improvement without fines migration. 43, 44 This brings a question mark to the consistency of this mechanism, with an explanation that it varies with mineralogy and lithology. For instance, the Berea sandstone used by Morrow

57

had

predominantly Kaolinite clay which is non-swelling; montmorillonite as a swelling clay would have different outcome. Another reasonable explanation originates from a hypothesis proposed by Brady et al.

58

who attributed clay release to rock/oil/brine electrostatic interaction at

kaolinite edges, states that clay migration occurs in most cases, except that these fines reattach to other surrounding walls and plug pore spaces which limit presence of clay particles in the effluent of core floods. 3, 37, 42, 59

Relating to permeability reduction, some authors say that fines are triggered, detached and migrate to block pores when LSWF is injected. When this occurs, water reconfigures its path from invaded pathways to sweep uninvaded areas. As a result, more initially uninvaded areas become accessed, potentially leading to overall better sweep and additional recovery. Consider an experimental setup to investigate permeability reduction when different waters (with different salt compositions) are injected to an oil-filled core. 60 In this experiment, the addition of certain salts to pure deionized water led to permeability damage. In summary, permeability reduction influences recovery efficiency due to fines migration aided by capillary effects, but whether this is always desirable remains a debate.61

Baptist 34 examined the effect of clay on permeability of reservoir sands to water of different salinities. Initial high salinity brine of 16,500 ppm sodium chloride was injected into the samples and subsequently lower salinity brine of 8,250 ppm. Permeability of sand to water decreased as salinity was reduced - particularly in the presence of mixed-layer clay. This suggests permeability damage as a mechanism of LSWF due to clay release, as Johnston and


Page 17 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Beeson 8 also demonstrated. This paper does not infer that permeability damage favors LSWF as reduced salts tend to hydrate clays, but rather suggests that clays could either cause subtle permeability reduction which may improve sweep efficiency or lead to extreme permeability damage which may reduce recovery factor drastically.

3.2.2

Electrostatic Interaction

Electrostatic interaction has been proposed as a mechanism because the rock formation, brine (both injected and formation brines) and crude oil, all contain charged ions. Researchers 5858585858 have demonstrated

interactions of these ions and their significance in LSWF – or smart

water injection. pH has also been identified as interconnected mechanism. For the purpose of this report, electric double layer expansion (DLE) will also be discussed in this section as an indicator of electrostatic interactions, particularly the DLVO (Derjaguin, Landau, Verwey and Overbeek) theory.

36, 58, 62

DLE is a manifestation of the DLVO theory which describes the

interactive charged forces that dominate in liquid medium, by accounting for electrostatic and Vander-Waal interactions. 36, 63, 64

Electric double layer (EDL) is a structure formed when a solid is immersed in a liquid medium. Close to the solid/liquid boundary consists of a static (or stern) layer of charges, while a dynamic (or diffuse) layer exists in bulk liquid phase, where ions can be exchanged. Thickness of double layer depends on electric charges at rock/brine and oil/brine interfaces which is evaluated by zeta potential, another electrostatic property.19, 64 As low salinity water is reduced, wetting water film becomes more stable, layers of similar charges repel, EDL expands and water-wetness improves.

65

Zeta potential values of +/- 10 mV or above (+/-

30mV) are assumed to be marginally stable while those below +/- 10 mV are unstable. Higher film stability increases with increasing EDL thickness and increasing zeta potential.64


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 18 of 74

Valluri et al. 19 conducted zeta potential measurements on two rocks which shows that films with increasing weight percentage (wt%) of CaCl2 are less stable than films with same increase in NaCl weight percentage, similarly observed by Filoco and Sharma.

65

Salinity reduction

from 5wt % to 1wt% NaCl led to a zeta change from -6.25mV to -19.63mV, which indicates increase in film stability. The more stable the films are, the greater the electrostatic repulsion, and thus increase in oil recovery. Nasralla et al. 64 conducted a similar experiment to determine impact of brine salinity and composition on zeta potential at Berea sandstone/brine and oil/brine interfaces. 10% dilution of seawater provided more negative charges at oil/brine interface than initial ionic strength (55 000mg/L) which means more expansion of double layer and larger thickness of wetting films. In both cases, zeta potential measurements have shown to be dependent on cation type. Also, it may be logical for zeta potential measurements on solid and crushed samples to differ, since both states exhibit different permeabilities 66, but this is of less importance since the focus is on surface chemistry and not flow transmissibility. Nonetheless, zeta potential measurement is effective in studying COBR systems: reflecting multiple surface properties14; examining influence of pH and ionic strength67, 68 examining presence of specific functional groups69; and investigating adsorption and desorption behavior of crude oil components on rock surfaces.

Stating that all LSWF mechanisms involve electrostatic interactions, Brady et al.

58

used a

Ph Ion Surface Electrostatics (IpHISE) model to predict pH behavior of oil surfaces and kaolinite as carboxylic functional groups adsorb on kaolinite edges. At high pH (8-9), electrostatics is controlled by rivalry between negatively and positively charged polar components produced by deprotonation (loss of protons, usually hydrogen ions) and calcium binding. Salinity effect was pronounced at pH of 5 - 6 where kaolinite/oil interaction becomes


Page 19 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

repulsive, with repulsion increasing for all salinities at pH greater than 6. The same authors also expatiated on the concepts of Bond Product Sum (BPS) and disjoining pressure isotherm from DLVO theory.

BPS is the combination of products of surface concentrations of oppositely charged species on oil and kaolinite edges, both of which are combined through electrostatic adhesion. If oil and mineral surfaces have the same charges, then BPS is zero, adhesion becomes unlikely and water wetness is improved. Made up of constant charge and constant potential, disjoining pressure is the differential pressure which occurs at the interface between oil and rock accounting for curvature and capillarity. Positive disjoining pressure indicates attraction while negative values indicate repulsion. For two different acid-base numbers, BPS reduces unpon injection of LSWF for a 5 to 6 pH range. However, discrepancy in behavior above this window shows the failure of BPS to describe LSE behavior for wide range of acidity/basicity levels. Increasing brine salinity reduces disjoing pressure isotherm (at small distances of 10-50nm where it is most effective) and causes a rupture in film thickness. Hence disjoining pressure (mathematical sum of electrostatic force and Van der waal force) reduces with increasing salinity. Pore roughness and rock asperities (kaolinite edges) also affects disjoining pressure negatively.17, 58

Kafili and Rao 12 performed contact angle studies to detect the role of sulfate ions in low salt water injection. Their results showed that sulfate ion was significant as water advancing contact angle improved from 158 to 115 when Yates brine was mixed with 4.4g/L sulfate. With this, they argue that sulfate ions (negative) attract positively charged rock surface, which makes the rock more negatively charged, thus leading to more electrostatic repulsion between oil and rock, and eventually wettability improvement.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

3.2.3

Page 20 of 74

pH

The exchange of active ions in LSWF usually involves change in pH, depending on controlling ions, rock surface chemistry and reservoir oil composition. Several mechanisms like clay migration, cation exchange, electrostatic interaction, double layer expansion and MIE have been identified with pH change for different reasons. 5 Brady et al. 58 stated that clay is negatively charged at high pH and positively charged at low pH. Baku and Sharma 17 proved in their microscopy experiment that solution pH increases with increasing disjoining pressure needed to promote wettability alteration. Sheng

70

proposed that cation exchange – which

depends on cation exchange capacity of rock and formation water composition - is related to pH such that at a given temperature, cation exchange increases with increase in pH. Often, active cations involved in this process are calcium and magnesium ions. LSWF is usually improved with more cation exchange, thus implying that increase in pH would favor recovery efficiency. However, this has not always been the case. Brady et al.

58

states that although pH

window of 5-6 is best for low salinity effects and pH will rise as decrease in Na+ levels prompt increase in H+ from water, CO2 dissolution during low salt water flooding of CO 2 –rich reservoirs should reduce pH or at least prevent any substantial increase from Na/H exchange. According to Omekeh et al.71 pH increase leads to greater electrostatic repulsion between low salt brine and rock surfaces. Nasralla et al.64 proved that pH decrease lead to a poorly negative charge at rock/oil/brine interface which favors neither crude oil expulsion from surface nor oil wetness.

Lager et al.35 identified carbonate dissolution as a source of pH change, which compares LSWF to alkaline flooding in terms of saponification i.e. formation of soap in the event that pH exceeds 9 in the reservoir 72. Carbonate dissolution is a relatively slower reaction (compared to fast cation exchange reaction) which results in excess OH -. Basic and acidic organic


Page 21 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

materials from crude oil adsorb on clay containing cations like Ca 2+. A chemical equilibrium is reached under prevalent conditions of pH, pressure etc. with pH of formation water being 5 or less depending on the dissolved carbon and sulphide gases. The injection of low saline water upsets the brine-rock equilibrium so that desorption of cations (Ca2+) occurs. Equations 4-6 are presented from Austad et al.56 which explains substitution of calcium by hydrogen from injected water and subsequent release of oil organics. Here, it is suggested that the replacement of multiple cations like Ca2+ causes a local increase of pH at the clay surface which then favors acid-base proton transfer reactions.

Clay-Ca2+ + H2O = Clay – H+ + Ca2+ + OH-

(4)

(H+/Ca2+ substitution) Clay-NHR3+ + OH- = Clay + R3N + H2O

(5)

Clay-RCOOH + OH- = Clay + RCOO- +H2O

(6)

(Desorption of organic materials through acid-base reactions)

Some authors say pH is of less impact on field recovery efficiency 73, others have concluded that the desorption of cations and carbonate dissolution3, 74 is key to pH increase and that pH increase is needed to release some pre-existing organic material and thus improve oil recovery. 56, 72

Based on these results, it can be hypothesized that LSWF is likely to increase pH locally

and at early injection periods, but this effect may be eventually offset by CO 2. Also, there is currently no direct correlation between pH change and improved oil recovery under LSWF.

3.2.4

Multicomponent Ion Exchange (MIE)

This phenomenon involves the replacement of formation ions present in connate water and those attached to clay sites with ions of injected brine or replacement of crude oil organics with injected cations. Usually, the ions which partake in substitution reactions are cations, hence the


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 22 of 74

focus on Cation Exchange Capacity of rock (CEC). CEC is a measure of the number of negatively charged sites present on a clay surface, in milli-ion equivalent per 100 g, or milliequivalent (meq) per 100 g. This property varies with different types of clay and is mostly affected by the presence of cations on the mineral surface. The more divalent cations adsorbed on the clay surface, the less negatively charged and hence the lower the CEC 75.

MIE in the context of LSWF was investigated by Lager et al.76 where other sub-mechanisms such as cation exchange and ligand bridging were discovered. During LSWF, Mg2+ and Ca2+ bridges negatively charged clay and carboxylate so that the organic material is removed via cation exchange between mineral and injected water. Electric Double Layer Expansion (DLE) then enables desorption of polar components. Yet, these statements were repudiated for a few possibilities: first, that precipitation of Mg (OH)2 was not considered; and second, that the change in Mg2+ concentration arose from a low salinity water/clay equilibrium which was established in the late stage of LWSF during a field test performed by BP. However, CEC was described as key to the performance of LSWF. 35, 56, 76, 77

Seccombe et al.78 reported BP’s Single Well Chemical Tracer Test (SWCTT) and proposed that MIE could occur through: cation exchange, cation bridging, ligand bridging and water bridging. In all cases, polar components strongly attach to negatively charged clay surface. During LSWF, divalent cations may replace organic complexes (as in cation exchange) or act as bridges between negatively charged crude oil and negatively charged kaolinite surface (as in cation bridging). Thus, at low salinity, it is expected that repulsion between oil and clay surface will occur, leading to detachment of oil molecules and additional oil production. It was also hypothesized in this work that MIE happens at the face of low salinity wave. According to Sheng70 , polar compounds (resin and asphaltene) on rock surface are either: bonded to


Page 23 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

multivalent cations forming organo-metallic complexes and stimulating oil wetness; or adsorbed directly on clay, displacing most labile (potentially unstable) cations present and improving oil wetness. LSWF should involve MIE, where complexes are deformed and polar oil components are also desorbed while new simple cations constitute replacement, which as observed by Lager et al.79 increases oil recovery.

Kafili and Rao

12

have also attributed decrease in contact angle during LSWF to MIE

between sulphate, calcium and magnesium ions present in brine which initially attached but subsequently released carboxylic oil components from rock surface. In Lager et al. 79 ’s work, 6% additional oil recovery was obtained with a tertiary LSWF. Conducted experiments indicated that additional oil recovery depends on connate water saturation brine composition i.e. removal of Ca2+ and Mg2+ in connate water before waterflood, irrespective of salinity, will improve recovery efficiency. 80

3.2.5

Desorption of Polar oil components

In many cases, it has been proven that certain crude oil components are responsible for wettability alteration.3, 57, 79 Researchers have demonstrated that difference in carbon number (e.g. hexane and pentane) are also significant in how crude oils respond to LSWF.29 Acid to base ratio is also a determinant factor in behavior of salinity contrast with polar crude components.81 Since there is a general consensus that LSWF causes wettability changes, it must be that these polar oil components affect the efficiency of LSWF in one way or the other. In another study to investigate influence of crude oil composition on mineral adsorption and wettability alteration, Berea sandstone cores were contacted with multiple types of crude oils to determine effects of oil composition on mineral adsorption and wettability alteration.82 A comparison of oil chemical and physical properties showed that one type of crude oil,


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 24 of 74

Huntington Beach, produced the most severe wettability change. As expected, it possessed the highest viscosity, base number, aromatic, resin and asphaltene contents. The cores flooded with Huntington Beach crude yielded the highest levels of adsorbed organics. The influence of certain crude oil components can be viewed from different perspectives based on their behavior in response to LSWF. Majority of the cases involving the adsorption or mobilization of acid, bases and asphaltene components have shown that as crude oil detaches from rock surface or as organo-metallic complexes deform, water-wetness improves. In this section, the following concepts are reviewed: polar component desorption, micro-dispersion formation and retention of polar oil components.

With respect to polar component desorption and micro-dispersion, Sohrabi et al. 9 performed a follow up work83,

84

on multi-scale spontaneous- and forced-imbibition experiments on

reservoir cores to investigate the role of the micro-dispersions in wettability alteration and oil recovery. Micro-dispersions are water micelles encompassed by certain crude oil surfactants. A coreflood experiment was performed with silica core and asphaltene-rich oil to eliminate effect of clay and emphasize on the surface-active components of crude. High salinity and low salinity brines used were 100,000 and 500ppm respectively. During spontaneous imbibition experiments, low salinity brine provided approximately 9% additional recovery. For forced imbibition, LSWF provided 6% more oil recovery efficiency. Water-wetness improved from an Amott index of 0.08 to 0.23. Infrared spectroscopy showed that produced oil was richer in bonds corresponding to sulfur, oxygen, nitrogen and SARA components of crude oil – generally heavier components of crude oil. Tetteh et al.85 also observed formation of mircodispersions which concluded was responsible for recovery improvement from a limestone rock with no clay content. Migration of surface-active components between oil-brine


Page 25 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

interface and bulk of oil has also been proposed but with little or no experimental evidence.83, 84, 86

Regarding the retention of polar oil components, Fjelde et al. 87 examined the effect of crude oil composition on LSWF, which is an improvement on previous research by Fjelde et al. 81 Retention of polar oil components onto reservoir rock was investigated for two crude oils with different compositions and brines with different compositions (high and low salinity). Absorbance and concentration of polar crude oil components was determined by preparing standard samples both for untreated (USTO) and treated stock tank oil (TSTO) respectively. When diluted USTO was injected to the packed column saturated with Low salt water (LSW1), the effluent oil concentration was in the beginning lower than in the case with formation water (FW), indicating retention of polar crude oils. Low salinity brine prepared by diluting FW has also been found to give higher total concentration of adsorbed divalent cations on the reservoir rock surfaces than FW.

81, 88, 89

for instance, retention of polar oil components onto mineral

surfaces was also found by Fjelde et al. 88 to increase with increasing total divalent cations concentration. Clearly, this effect is controversial, and a reasonable explanation could be that perhaps low salinity water used in Fjelde et al.87 contained more divalent cations than formation water.

3.2.6

Osmotic Effects

Recent studies indicate that LSWF improves oil recovery through osmotic diffusion.

90, 91

Osmotic diffusion primarily occurs from the creation of salinity gradient between formation water (connate brine) and injected brine through an oleic phase which serves as a semipermeable membrane. Contrasting salinity levels in formation and injected water creates a chemical potential between two saline phases, known as osmotic potential. 90 Basu and Sharma


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

17

Page 26 of 74

explains that electrostatic interactions between crude oil, brine and mineral surfaces due to

reduced salinity leads to EDL. This EDL effect is multiplied in the presence of several interfaces in solution, leading to overall rise in film counter-ion concentration and thus resulting in osmotic potential. Hence, osmosis may possibly be related to electrostatic interactions in LSWF.

Fredriksen et al.29 performed a comprehensive study on micro-scale oil mobilization by water diffusion and osmosis during LSWF using microscopic visualization in sandstone silicon-wafer micromodels. The micromodels incorporated sharp edges and rough surfaces – important features in porous media studies58 - to replicate subsurface displacement. The oil-phase represented a semi-permeable membrane in presence of an osmotic gradient to transport LSW into high-saline water-in-oil emulsions. An oil-saturated region was established to separate the initial high-saline brine from the injected low salinity water to set a salinity gradient across the matrix oil-phase. During LSW, diffusion of low salinity water to high-salinity connate brine has shown to be important in mobilizing trapped oil through film-expansion and water-droplet growth. Expansion of water-in-oil emulsions may also be the result of osmosis. 5, 42, 56 Timelapse images were captured during 8 days of LSW for a given oil-droplet in matrix where water is transported into water-in-oil emulsions by osmosis. During the diffusion process, almost 50 % of the oil surface area was displaced from the pore by developing water-dispersions. Similar work was done by the same group91 but with the use of capillary tubes. Results showed expansion of high saline regions upon LSWF and eventual production of more oil out of the HS-oil-LS configuration. It was concluded that an oil-wet system offers the most ideal case for osmotic effects but osmosis is itself largely independent of system wettability.


Page 27 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

According to Sandengen and Arntzen92 , osmosis is bound to occur in an oil/water/rock system when injecting low salinity water, because multiple semi-permeable membranes are bound to exist in oil-saturated rock pores. Their work involved the use of brine-filled capillary tubes of different salinity separated by an oil droplet, with oil-phase acting as a semi-permeable membrane. Oil droplets were observed to move under the influence of an osmotic gradient in a simple visualization experiment. For a porous rock medium, such osmotic gradients relocate oil by expanding an otherwise inaccessible aqueous phase. Water molecules were transported into HS brine. Increased osmotic pressure within the brine caused expansion and displaced neighboring oil phase. It was also suggested that water flux into inaccessible brine-filled pores is a displacement mechanism to relocate oil during core floods.

3.2.7

Wettability Alteration

Wettability alteration is the most recognized mechanism behind LSWF, because it explains how the preference of a particular rock to contact oil in place of water or vice versa varies with change in certain conditions, including brine salinity change. Another strong reason for its dominance is that wettability directly affects relative permeability, an important rock-fluid descriptor and macroscopic efficiency controlling parameter. Several mechanisms like multiion exchange (MIE), polar component desorption and fines migration have been attributed to wettability changes. The presence of an initial oil-wet or mixed-wet state on a rock surface is a key requirement for the success of LSWF as most of these mechanisms thrive to steer the wettability of the rocks towards a more water-wet state. In the first publication of an inter-well field trial on Endicott field, wettability change via MIE was the indicated mechanism for reduced-salinity EOR.12, 35, 36, 56, 63, 72, 73, 77, 93-96


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 28 of 74

The concept is by far the most comprehensive also: as wetness improves from say oil-wetness to mixed-wetness or mixed- to water-wetness, more oil is released from the rock surface leading to greater exposure of the rock to water. The oil released from surface also contributes to additional oil production while exposure to water enhances imbibition via film flow. The more water-wet the rocks become, the more presence of water coating films are established, thus increasing oil relative permeability and reducing connate oil saturation. Through contact angle studies, Kafili and Rao12 observed: shift from left to right in fractional flow curves, shift from left to right in oil/water relative permeability ratio curves and water saturation at cross over point, all of which indicates improvement in oil sweep efficiency.

Contact angle is the most universal measure of wettability.57 Hence, contact angle change is a manifestation of wettability alteration, not necessarily a separate mechanism. The more widely accepted classifications of contact angle are: 0-75: water-wet; 75-115: intermediatewet; 115-180: oil-wet.97 As part of Schlumberger’s investigation on fundamentals of wettability, contact angle was examined using pore surface-like crystals, formation brine and oil. An oil drop was placed in between the brine-aged crystals, and the bottom crystal was displaced, keeping the top crystal stationary. Oil slides onto water-wet surface, yielding waterreceding angle while water moves onto aged surface in contact with oil, yielding wateradvancing contact angle.98 Kafili and Rao12 diluted reservoir brine to 2% initial concentration and observed wettability change from oil-wet state (158 water advancing contact angle) to intermediate state (113). Alameri et al.99 also observed contact angle change from oil wet state (140) to intermediate state (108) during experimental modelling of LSWF in a tight carbonate reservoir. Valluri et al.19 carried out contact angle measurements and observed that contact angle decreased with increasing NaCl and CaCl2 concentrations and increased after an optimum level. Their reason


Page 29 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

for this anomaly was that there is an optimum low salinity concentration beyond which waterwetness is not improved. Nasralla et al.64 recorded 75 and 30 contact angles on a mica surface when sea water (55,000mg/L) and NaCl (5,000 mg/L) were examined respectively. Contact angle change may also be indirectly used to infer capillary pressure differential under the influence of LSWF.46

3.3

Reservoir Simulation Studies

Modelling of LSWF have been performed with black oil models 13, 73, 96, 100, in-house industry sector models101, 102 , compositional models39, 72 and even 1-D numerical model.99 Majority of the numerical black oil model implement LSE using salinity-dependent relative permeability curves. However, the prediction of LSE requires more than what a “mass-transfer only” model offers. Brine chemistry should be factored and can be reasonably analyzed by a geochemical model. Ions in brine have been grouped into two categories depending on their chemical reactivity, namely: divalent and monovalent ions. Likewise, different types of clay exhibit different behaviors with either brine or oil, some of which are: kaolinite, illite and montmorillonite. Geochemical models allow proper investigation of clay content and injected brine compositions in conjunction with certain polar oil components which are found to be influential in electrostatic interactions at rock/oil/brine interfaces. The clay content model from Dang et al.’s103 modelling study was built on the hypothesis that grain size varies inversely with clay content.104, 105 Clay-dependent grain sizes were assigned to the 3 different facies considered: Fine-Grained (FS), Medium-Grained (MS) and Coarse-Grained sandstone. Cation exchange capacity as a function of rock organic carbon content and clay as proposed by Breeuwsma et al.106 (1986) was also factored.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 30 of 74

The contribution of geochemistry to LSWF comes in three phases: intra-aqueous reactions, ion-exchange reactions and mineral dissolution.72 PHREEQC invented by US Geological Survey is industry-standard geochemistry software that fully incorporates geochemistry in the displacement efficiency of brine injection in all types of oil reservoirs. Korrani et al. 39 combined PHREEQC with a non-thermal compositional reservoir simulator known as UTCOMP to study organometallic complexes in addition to geochemistry. UTCHEM simulator is another reliable prediction tool for reservoir performance upon injection of brines with different compositions.70 In geochemistry analysis, specific ion compositions (e.g. CO 2, Na+, Mg2+), activity coefficient, species molalilty, selectivity coefficient, clay-ion equivalent fraction must be specified in additional to common parameters like temperature, pH etc. Important mechanisms which have been recognized in lab work on LSWF like ion exchange with clay surface (cation bridging) with103 or without72 specific facies may also be simulated. Often tied to wettability alteration, this mechanism is examined by the conversion of wetness in the model from oil-wet to water-wet conditions. An interpolant which is the equivalent fraction of a brine ion on clay surface (Na-X/Ca-X) has been found to affect wettability and can be used to model relative permeability shifts. If the equivalent fraction exceeds a certain maximum threshold, oil-wet curves are used and below a minimum threshold water-wet curves would apply. The low salinity transition is effected through interpolations between minimum and maximum thresholds.

Finally, geochemical simulation may either be performed based on a certain mechanistic premise or be used to confirm certain effects. For instance, Dang et al.72 developed a model to investigate ion exchange with clay surfaces on the assumption that clay- ion interactions predominantly affects wettability change. Dang et al.

103

observed the replacement of sodium


Page 31 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

ion with calcium in LSW, which although contradicts Omekeh et al.’s81 conclusion, is in agreement with coreflood results of Fjelde et al.81 (2012) and Rivet et al.107 Thus, it is important that these premises are observed with a reasonably high confidence level elsewhere (e.g. in lab experiments) before they are considered in simulation.

4. FIELD OBSERVATIONS: LOG-INJECT-LOG TESTS, SINGLE WELL CHEMICAL TRACER TESTS (SWCTT), PILOT TESTS, FIELD DEVELOPMENT PLANS The first field implementation of Low Salt Water Flooding was made by British Petroleum (BP), which eventually led them to corporately register its name as LoSalTM. The BP R&D team have conducted coreflood experiments, log-inject-log tests, SWCTT which have all shown positive results. This has encouraged the deployment of LSWF in gigantic Oil fields like Endicott93 and Clairidge.108 Likewise, numerous multinational companies101, 109, 110 have also attested to the success of LSWF and are willing to continue investing research and development to properly reveal the underlying mechanisms and design highly economic and efficient surface desalination treatments.

Webb et al.4 presented results of the first log-inject-log test of LSWF which was carefully designed to verify the effect of injecting reduced salinity brine on connate water saturation at reservoir scale. The technique is based on making multiple runs of Pulsed Neutron Capture (PNC) logs - observing capture cross-sectional differences after injecting high and low salinity brines. The reservoir interval logged is one in a giant clastic reservoir with porosity ranging between 0.2 and 0.3, permeability between 200 and 700mD, and principally consisting of quartz (70% - 95%) and trace amounts of kaolinite, plagioclase, illites and smectites. Oil API ranges between 12-33 degrees, with 23% irreducible water saturation. Salinity of aquifer water averages at 250,000ppm. 10 – 15 pore volumes of 220,000ppm high salinity brine was injected


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 32 of 74

while low salinity brine injected was 3,000ppm, both principally consisting of NaCl. Although, the effect does substantially vary across intervals, there was a general increase in water saturation in LS case compared to HS, implying lower oil saturation and improved recovery.

Seccombe et al.78 reviewed effect of brine composition on LSWF recovery on Endicott field by performing SWCTT to evaluate the mechanism and quantify recovery benefits. Endicott has initial oil saturation of 95%. Based on SWCTT, average oil residual saturation after secondary (high salinity) waterflood is 41%, and the average residual oil saturation after tertiary LSWF is 27%. A 30% pore volume slug was essential for slug performance over sample’s entire length. The 10% slug did not produce any more oil but 40% slug recovered 87% of the oil recovery by continuous LSWF. Petrology of Endicott field shows that LSWF is likewise influenced by the rock mineralogy as drop in residual saturation significantly varied with kaolinite clay fraction. The most dominant pore-filling constituent is quartz, followed by kaolinite clay – a mineral which has been vital in other LSWF research.3, 58 It should be mentioned here that McGuire et al.74 performed similar multiple SWCTTs in Alaska which demonstrated high success of LSWF at reservoir scale (6 to 12% OOIP, 8 to 19% waterflood recovery efficiency).

Seccombe et al.93 published results of the first inter-well field trial. Their aim was to demonstrate that LSWF is efficient in the field - beyond laboratory tests. A 30-45 feet thick reservoir zone of high clay content at Endicott field was the zone of interest, with injector and producer wells 1,040 feet apart. The high clay content should be beneficial to low salinity response. Produced fluids were monitored for water cut and ion composition variations. HS brine was injected in December 2007 while LSWF began nearly 6 months after. A response was detected three months after the start of LSWF injection. Six different inter-well tracers


Page 33 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

(difluro- and trifluoro- benzoic acid) were placed in pilot injection. The proposed mechanism for LSE is MIE-induced wettability improvement. The arrival of reduced salinity water led to increase in oil rate. Reduction in water cut was also observed. Based on high clay content, a normalized set of graphs shows that incremental recovery observed from pilot test clearly matched that of coreflood experiments. After 11 months, estimated incremental recovery of 10% was observed upon nearly 1.6 pore volume of low salt water injection.

Robbana et al.

108

discussed steps taken in the Clair Ridge project to administer LSWF as

EOR candidate. The success of this project solely relies on results of core flood experiments which were performed in 2006 since SWCTTs and field trials were not permissible. The field contains a sandstone reservoir with average permeability of 50mD, oil of 3.2cP viscosity and highly heterogeneous with open fracture networks. Laboratory tests show that some underlying mechanisms of LSWF are cation exchange and cation bridging, as Seccombe et al.78 reported. Forty-eight sector models were developed to provide more robust evidences of LSWF at reservoir scale and 98% of these models indicated positive responses. The results of these simulations and laboratory experiments have successfully convinced Clair Ridge field operators to invest in topside facilities, which includes confirmation of engineering feasibilities and impact of integrating membrane facilities into topsides.

The Pervomaiskoye oil field in Russia is one which Low salinity water flooding was used in its early secondary-recovery life.37 Discovered in 1958, gross thickness of the reservoir is about 30m while net pay thickness ranges between 8-18m.Waterflooding began in 1966, and due to deficiency of produced water, the nearest water source, Kama river was used to inject low salt water for 40 years. Akhmetgareev and Khisamov37 presented likely results of oil recovery efficiency obtained during LSWF by analyzing seven field pilots. LSE has shown to have


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 34 of 74

provided 5-9% incremental recovery upon high salinity water flooding through field production and injection data. The mechanisms identified with the success of LSWF with Pervomaiskoye field are fines migration, permeability damage and wettability alteration.

Eni began investigation of LSWF in 2006, and a West African field was selected for study. Log-inject-log and SWCTTs were first carried out in 2008 and 2013 respectively. Some of the established requirements for LSWF are: less than 6g/l salt content, presence of clay, presence of divalent ions and also that of polar oil components. The sandstone reservoir is associated with large-scale fractures and heterogeneity. Crude oil has viscosity of 0.5cP and API of 39 degrees. Though SWCTT results showed that sea water injection gave an average connate oil saturation of 21% which matched Special Core Analysis Data (SCAL), low salinity water flooding did not yield any significant reduction (0-3 saturation units), despite good laboratory forecasts.110

5. DISCUSSION 5.1

Evolution of LSWF Research and Conflicting Results

The objective of this paper is to condense and present observations and results of relevant research performed to investigate LSWF from atomic scale relevant for mineral surface interaction with fluids, to microscopic scale (porous media flow) and finally to the field scale via reservoir simulation. Though research on influence of salinity on oil recovery began several decades ago, the evolution of research work on LSWF from 1945 till date significantly improved particularly from 2004. Research output steeply progressed and this may be partly ascribed to BP’s successful exploit at field scale when Log-inject-Log tests showed positive results.4 The review depicts how influence of clay content, mixed wetness and polar oil components have long been identified as necessary conditions that enhance LSWF, but recent studies have shown otherwise.16, 91, 111 The more recent advanced research now tends to play


Page 35 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

down many of the conditions which were initially regarded as important in smart water injection a number of decades ago and clearly invites further studies and an interdisciplinary approach to clarify existing conflicting ideas.

5.2

Qualitative and Statistical Analyses of Conditions and Mechanisms

Table II below shows classification of already reviewed identified mechanisms and conditions in order of importance and frequency of observation. Degree of importance was decided based on how each mechanism contributed to incremental recovery efficiency, while frequency of observation was determined based on the number of publications selected for this summary report.

As shown, wettability alteration and clay migration appear as leading mechanisms, but certain discrepancies observed as regards the latter leaves wettability change as the most dominant mechanism. Desorption of crude oil components and pH have also been identified as reasonably frequent explanations for improving recovery through reduced salinity but for separate reasons, there is not large consensus that supports both. Although certain pH values have appeared more favorable than others, there has been no consistency as to what range and trend of pH is expected.

Table II. Classification of mechanisms and conditions underlying LSWF in terms of observation frequency and degree of importance. Primary mechanisms

Impact on Frequency Necessary In-situ LSWF of Literature sources conditions EOR Observation

Wettability alteration

Clay presence, Polar oil High components, Injected/Formation water salinity

High


Approximately 70% of reviewed papers in this study

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

contrast, wetness, cations, ions,

Fines Migration and Mineral Dissolution (with/without permeability reduction)

Page 36 of 74

mixed divalent sulfate

Presence of reactive clay, Injected/formation Medium water salinity contrast

Electrostatic Interaction

Injected/formation water salinity Medium contrast

Multi-Ion Exchange

Ca2+, Mg2+ and Na+, Injected/formation water salinity Medium contrast, high cation exchange capacity

Polar oil Desorption components, of crude oil Injected/Formation Medium components water salinity contrast

High

Johnston and Beeson 8, Baptist34, Bernard 41, Tang and Morrow3, Lager et al.35, Rivet et al.107, Sheng 36, Kafili and Rao 12, Morrow and Buckley 42, Pu et al.43, Loahardjo et al. 44, Akhmetgareev and Khisamov37

Medium

Filoco and Sharma 65, Ligthelm et al. 62, Lee et al.112, Pu et al.43, Austad et al.56, 63, Nasralla et al. 64, Sheng36, Kafili and Rao12, Brady et al.58, Valluri et al.19, Mahani et al.14, Shehata and Nasr ElDin 113

Medium

Sheng36, 70, Shehata and Nasr El-Din54, Valluri et al.19 Lager et al.35, 76, 77, 79, Seccombe et al.78, Austad et al.56

Medium

Tang and Morrow114, Wolcott et al.82, Lager et al.79, Bai et al.86, Omekeh et al.71, Fjelde et al.81, 87, 88, Sheng36, Shehata and Nasr El-Din54, Fredriksen et al.29, Tang and Morrow3, Emadi and Sohrabi83, Mahzari and Sohrabi84, Sohrabi et al.9


Page 37 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

pH change

Polar oil components, Injected/formation Low water salinity contrast

Osmotic potential

Sulfate ions, SemiPermeable oil membrane Low injected/Formation salinity contrast

High

Approximately 45% of reviewed papers in this study

Low

Zhang et al.5, Austad et al.56, Morrow and Buckley 42, Ellila90, Sandengen and Arntzen92, Fredriksen et al.29, 91

Contact angle change is a manifestation of wettability alteration but it often does not take into consideration pore morphology. MIE and electrostatic interaction have been investigated with a number of good results. Zeta potential measurements have supported the hypothesis that salinity reduction increases electrostatic repulsion but there are still conflicts as to if EDL actually improves recovery efficiency and which cations are dominant. Most research, which involved taking coreflood experiments from ambient to reservoir temperature, have observed positive changes, since temperature increase results in the dissolution of clay-bound ions and even organo-metallic complexes, leading to additional oil recovery.52 However, reducing salinity while maintain reservoir temperature does not have the positive impact on recovery, thus the latter cannot be said to be an underlying mechanism. Osmosis effects have just recently gained recognition, and further research should provide more substantial effects. In an audacious attempt to statistically analyze conditions and mechanisms that have been discovered over decades, Figure III is presented below. This figure illustrates how what percentage of reviewed publications have ascribed incremental recovery efficiency provided by LSWF to each mechanism. Indeed, reports have suggested certain mechanisms like pH and fines migration, but failed to prove it. Therefore, such mechanisms cannot be documented as indications of LSE in oil recovery. Complementing the quantitative analyses, osmosis records low percentage because it only received R& D attention a couple of years ago. We perceive


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 38 of 74

this effect to be substantial, and we expect future studies to reveal high relevance of osmosis. Although many authors hypothesize that pH affects oil recovery through LSWF, only few have been able to directly correlate these two events. Our report shows that fines migration is the “oldest” mechanism.8

Yet, many cases from corefloods to field applications have reported additional production without high clay presence or release of fine particles. For instance, in carbonates, there is no evidence of clay presence. This has thus limited the popularity of fines migration. Electrostatic interaction has been analysed through zeta potential, small angle scattering and Atomic Force Microscopy. It is no coincidence that it records similar percentages with MIE and polar component desorption; in most cases, they are interconnected. Divalent ions attach either rock mineral surface or to polar crude components. Subsequent reduction of divalent ions from injected brine leads to ion exchange between formation and injection brine, expansion of electric double layer and eventual expulsion of crude oil polar components from rock.

Percentage of selected reviewed papers (available in references section) that have identified LSWF mechansims from 1945 to 2017

Osmosis

pH

Fines migration with/without permeability reduction

Electrostatic interaction

Polar component desorption

MIE


0

10

20

30

40

50

60

70

80

90

Figure III. Statistical analyses of conditions and mechanisms identified with LSWF. All reviewed papers are available in references section. From Top to Bottom: Osmosis records low


Page 39 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

percentage because it has received least R & D efforts. pH has though been reported by many researchers but very few have directly correlated pH change with recovery increment during LSWF. Fines migration have long been in existence8 and is thus a popular mechanism but multiple field applications and Lab experiments have played down its influence in LSWF EOR. Electrostatic interaction, polar component desorption and MIE are mostly connected but with few exceptions. Finally, wettability alteration remains the most dominant mechanism being the most fundamental property that describes crude oil/rock/brine interactions. However, it is believed in some instances that multi-component ion exchange does not influence surface charges. Similarly, in other cases, electrostatic interaction has led to expulsion of crude oil from mineral surface, but there is no particular focus on the composition or polarity of oil. All these have led to the different results in the three mechanisms. Finally, wettability alteration remains the most dominant mechanism at all scales of investigation, with several reasons. First, it is the most fundamental flow property that describes the relationship between rock and fluid interactions in multiphase flow. As such, majority of other mechanisms except osmosis have been directly or indirectly linked to wettability improvement. Amott indices and contact angle measurements which directly measure wettability have also consolidated existing general consensus.

5.3 5.3.1

Quantitative analyses of Recovery Efficiency Results Coreflooding experiments, Reservoir Simulation and Field Implementation

Figures IV and V present results of incremental oil recovery observed during LSWF (in addition to HS recovery) from pore-scale and reservoir-scale investigations respectively. From reviewed coreflood experiments, recovery increases ranged from 2- 30% across different reservoirs from North America, Africa and the Middle East. Researchers have ascribed many reasons for incremental recovery during core floods. Formation/injection water salinity


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 40 of 74

contrast, kaolinite content, sulfate content, multicomponent ion exchange and crude oil desorption have been ascribed to LSWF success.

5.3.1.1 Outcrop Vs. Reservoir samples Cores experimented upon by Winoto et al.

115,

namely: Berea Stripe 1, castle Gate 1, Idaho

hard 1, Boise 1, Bandera Brown 1, Kirby 1, Torrey Buff 1, Leopard 1, Bentheim 1 and Cedar Creek generally showed little responses to reduced salinity injection even though they met the necessary conditions like presence of clay and mixed-wetness.3 There were two reasons for this: all samples are outcrop samples and clay structures are significantly different from regularly stacked kaolinite structures which the likes of Brady et al.58 have observed to be crucial in LSWF. It should be mentioned that all other cores plotted were obtained from actual producing reservoirs.

5.3.1.2 Clay (Kaolinite) Vs. No Clay Many researchers propose clay presence to be a mandate in LSWF process, but results presented here shows that even in sandstones, LSWF can improve recovery factor without high kaolinite contents, and in carbonates, influence of clay structures are more or less irrelevant. AlQuraishi et al.116 performed experiments on local reservoir sandstone and carbonate samples. Carbonate cores (Saudi Carbonate) contained dolomite with traces of anhydrite, while sandstone samples (Saudi Sandstone) contained quartz with kaolinite clay impurities, though the report did not state the weight percentage of minerals. The cores examined by Shehata and Nasr-El-Din

113,

namely: Bandera SN, Parker SN, Gray Berea SN and Buff Berea SN had

kaolinite contents of 3%, 2% 6% and 3% respectively. The low recovery output observed with Parker SN sample is largely due to its smallest pore size and highest capillary pressure compared to other samples. Shehata and Nasr-El-Din113 concluded that presence of clay was


Page 41 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

not necessarily the primary mechanism in their experiments, although EDL due to kaolinite content might be an important factor (from zeta potential measurements). Bu Hasa carbonates 1, 2 and 3 observed by Al-attar et al.117 all showed encouraging results, thus suggesting that clay presence is not a compulsory condition.

For the purpose this review, we label Bu Hasa Carbonates not because different rocks were used but due to different brine compositions selected. Al-attar et al. 117 inferred that increase in sulphate concentration in the injected brine tends to change the wettability to more intermediate levels and improved ultimate oil recoveries. Akhmetgareev and Khisamov37 performed coreflood experiments on two Pervomaiskoye Field cores (Pervomaiskoye 1 and 2) where they observed that increasing Ca2+ concentration in injected brine resulted in decreased ultimate oil recoveries. Pervomaiskoye 1 has 0.8 % clay while Pervomaiskoye 2 had 0.1% clay. Thus, they concluded that ionic interactions between injected brine and formation water improved wettability which in turn gave rise to additional recovery, thereby discounting impact of clay.

5.3.1.3 LSW/Formation Water Dilution factor Review also shows that responses of selected core samples to LSWF can be partly attributed to dilution factor between injected and formation brines. We will exclude results of outcrop samples from these analyses. For all cores used in Winoto et al.115, low salt water was prepared by diluting formation water 20 times, resulting in 1780ppm, with no sensitivity analyses on dilution factor. Similar case applies to AlQuraishi et al. 116 with Saudi Sandstone and Saudi Carbonate where seawater was diluted ten times to yield LSW of 6835.8ppm. however, from Kafili and Rao 12’s experiment, it was observed that increasing dilution factor from 2 to 50


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 42 of 74

followed an increase in oil recovery, with subsequent increase in dilution factor yielding less recovery. Similarly, Bu Hasa Carbonate 2 led to significantly less recovery than Bu Hasa carbonate 3 for the same LSWF composition but with different formation brines (FW). In Bu Hasa carbonate 2, LSWF was 5,000ppm against FW 197,000ppm whereas FW was 43,000ppm for Bu Hasa Carbonate 3. For Bu Hasa Carbonate 1, FW used was 224,000ppm with same LSWF composition of 5,000ppm.

Other samples were flooded with constant dilution factors: Sohrabi et al.9 diluted HS from 1000ppm to 500ppm, Akhmetgareev and Khisamov

37

used a dilution factor of 300+ in their

experiments, Shehata and Nasr-El-Din 113 used a dilution factor of approximately 35 (LSW – 5000ppm; FW – 174, 156ppm).

In summary, what we see is that dilution factor is case-specific i.e. there is no definite array of dilution factors that best suits LSWF. However, in most cases, there is a maximum factor beyond which salinity reduction does not increase recovery efficiency. This is logical in that LSWF lies somewhere between two ends of salinity spectra, being freshwater flooding and conventional high salinity (formation water) flooding.

5.3.1.4 Contribution of Multiple Mechanisms Researchers have proposed many reasons for incremental recovery during core floods. As discussed earlier, Formation/injection water salinity contrast, kaolinite content, sulfate content, multicomponent ion exchange and crude oil desorption are some of these. Cores experimented upon by Winoto et al.115, namely: Berea Stripe 1, castle Gate 1, Idaho hard 1, Boise 1, Bandera Brown 1, Kirby 1, Torrey Buff 1, Leopard 1, Bentheim 1 and Cedar Creek generally showed little responses to reduced salinity injection even though they met the necessary conditions like


Page 43 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

presence of clay and mixed-wetness.3 AlQuraishi et al.116 attributed improvement of oil recoveries for Saudi Carbonate and Saudi Sandstone to MIE, sulfate presence and wettability modification.

Kafili and Rao12 also maintains that sulfate content engages in electrostatic interaction with carbonate charges to detach surface-active components and improve wettability. Sohrabi et al. 9

(Sandstone Sohal) observed formation of oil micro-dispersions leading to incremental

recovery observed in their experiment. Shehata and Nasr-El-Din 113 concluded that presence of clay was not necessarily the primary mechanism in their experiments, although EDL due to kaolinite content might be an important factor (from zeta potential measurements). Increasing the Ca2+ concentration in the injected brine resulted in decreased ultimate oil recoveries. For Bu Hasa carbonates, Al-attar et al.117 inferred that increase in sulphate concentration in the injected brine tends to change the wettability to more intermediate levels  and resulted in improved ultimate oil recoveries. On the other hand, Akhmetgareev and Khisamov37 performed coreflood experiments on two Pervomaiskoye Field cores (Pervomaiskoye 1 and 2) and concluded that ionic interactions between injected brine and formation water gave rise to additional recovery.


Energy & Fuels

Incremental Oil Recovery during LSWF observed during Coreflooding of Outcrop and Actual Reservoir core samples Recovery efficiency (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 44 of 74

100 90

Small incremental recovery observed are due to: outcrop sampling and uncharacteristic clay structures Low pore size and high capillary pressure

80 70

Substantial difference in recovery factors for the same core is partly due to different dilution factors

60 50 40 30 20 10 0

HS Recovery (% OOIP)

Figure IV.

incremental oil recovery from HSWF (% OOIP)

Comparison of Percentage Incremental Oil Recovery observed during

Coreflooding of Outcrop and Actual Reservoir core samples. From Left to Right: Investigated outcrop samples showed very little improvements in oil recovery. Type of Clay (kaolinite) structures also affected recovery factor, though clay presence was not always necessary condition in this study.

Likewise, other mechanisms were responsible for Carbonates’

performance: sulfate content, electrostatic interaction and wettability improvement. Blue bars represent oil recovery by high salinity water while orange bars represent incremental oil recovery by LSWF.

Table III. Summary of coreflood results reported from literature indicating reduction of oil saturation and increase in recovery efficiency for different rock types. Author

Rock type

Percentage oil saturation reduction

Pore Volum e of injecte d LSW

Pore HSW volume recovery of High salt water


Percentage increment al recovery (LSWF)

Page 45 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

injecte d

Winoto al.115

et Briar Hill Aac- 11.64 4

3.5

16.6

41.13

4.79

Berea Stripe 1

4.41

3.5

18.3

51.52

2.27

castle Gate 1

10.61

5.7

12.4

43.71

4.64

Idaho hard 1

18.75

21.3

16.4

30.77

5.77

Boise 1

1.5

2.8

16.3

72.68

1.09

Bandera Brown 4.35 1

3.6

16.7

45.54

1.98

Kirby 1

3.7

2.1

20.8

45

1.67

Torrey Buff 1

3.23

0.4

24.3

40.26

1.3

Leopard 1

3.02

3.6

17.1

34.74

1.05

Bentheim 1

1.79

8.4

18.5

68.29

1.22

Cedar Creek

1.75

5

12.2

42.22

0.74

AlQuraishi et Saudi al.116 carbonate

22

8

64.28

16.43

Saudi sandstone

11

6

50.91

18.19

4.5

4

47

30

9

4

49.22

11.82

18

18

33.2

9.2

Parker SN

19

20

24.6

4.3

Gray Berea SN

15.5

15.5

38.3

13.3

Buff Berea SN

13

14

44.4

17.1

22

10

46.5

25.5

Kafili and Rao Silurian 59 dolomite KR Sohrabi et al.9

19

Sandstone Sohal

Shehata and Bandera SN Nasr-El-Din 113

Al-attar al.117

et Bu Hasa carbonate 1


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Bu Hasa carbonate 2

19

13

58

24

Bu Hasa carbonate 3

17.5

21

58

2

0.003

22

33

0.002

21.5

41

53

7

Akhmetgaree Pervomaiskoye v and 1 Khisamov 37 Pervomaiskoye 2 Rotondi al.110

Page 46 of 74

et North Africa

72

75

Using reservoir simulation, majority of incremental recovery observed were attributed to influence of capillary forces leading to wettability alteration i.e. increase in relative permeability of rock to water and corresponding decrease in oil relative permeability as a driver of wettability improvement.13, 72, 73, 100 Other researchers like Law et al.118 discovered that the association of low salinity with intra-aqueous and mineral reactions, in addition to clay content and acid number, are evidences of better EOR performance.

Elsewhere, incorporating kinetics of fines migration into modelling resulted in improved recovery.119 Zeinijahromi et al.

61

ascribed similar mechanisms to oil recovery via LSWF as

Borazjani et al.119 but observed less recovery partly due to large volumes of formation water which were already produced prior to LSWF. This in line with Attar and Muggeridge’s120 observation that increase in oil recovery is proportional to decrease in HSWF and increase in LSWF. Korrani et al.38, 39 and Lee et al.40 performed adequate geochemical simulation which incorporated complexation of organometallic components as well as crude oil polar components to perform smart water flooding. Correspondingly, they agreed that additional oil produced is primarily as a result of substantial contribution of geochemistry. Alameri et al. 99 concluded that increase in oil recovery from LSWF is due to the alteration of crude-aged


Page 47 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

carbonate from oil-to-water wet. They also infer that homogeneity of rocks improve recovery. It is important to note that a merit of reservoir simulation (besides costs) over actual field tests such as LIL and SWCTT is that they incorporate geological complexities on a broader scale. As such, simulation results are to a large extent reliable for field development projects. 121

From a field implementation standpoint, LSWF has shown significant success in what few field cases examined. Webb et al.4, McGuire et al.74 and Seccombe al. 78, 93 have all reported how log-inject-log tests, single well chemical tracer tests show reduction in hydrocarbon saturation with smart water flooding. In light of these, Low salt water injection has become an established EOR method for Endicott field. 91,108 Robertson122 analyzed historical production data from fields which have been waterflooded with about 1,000ppm low salt brine and observed that their recoveries were higher than those under high salinity injection. Patil et al. 121,

Vledder et al.123, Seccombe93, Abdulla et al.124 and Zeinijahromi et al.61 all reported

substantial recovery increments ranging from 4 – 15 percent oil-in-place. Conversely, less than encouraging field cases have been observed. The first ever field trial in carbonates also reported reduction of hydrocarbon saturation by 7 saturation units.125 Skrettingland et al.111 reports that though the Snorre field exhibits the necessary characteristics for LSWE such as clay presence and mixed-wetness, there were no significant improvement in oil production. Thyne et al. 126 examined numerous fields in similar complexion but observed no recovery increment. A close examination of Thyne et al.’s 126 study however shows that the presence of anhydrite in these rocks might have obstructed the success of smart water injection. The less total dissolved solids in brine can lead to further dissolution of anhydrite, subsequently increasing the salinity of injected water.


Energy & Fuels

From a global perspective, the use of smart water injection is yet to be a generally accepted EOR technique for multiple reasons. One would expect field results to tally with reports from the encouraging laboratory experiments and reservoir simulation but this has always not been true, because, to start with, existing mechanisms are not fully understood. Perhaps profound understanding of these mechanisms may assist to properly modify the composition of injected brine to yield positive effects e.g. by diluting the entire brine or reducing the concentration of certain divalent ions. Another reason could be possibly the lack of investigation into new mechanisms and conditions such as effect of certain mineralogical contents and asperities which might hinder the success of LSWF. Reservoir Simulation Results Showing Incremental Oil Recovery of LSWF over HS brine Injection in Recent Years 100 Low incremental recovery was ascribed large produced Formation water prior to LSWF

90 80

Recovery efficiency

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 48 of 74

70 60 50

Overall low recovery efficiency as a characteristic of heavy oil reservoirs

Low incremental recovery was ascribed to low rock permeability: 0.5mD-1.5mD


40 30 20 10 0 Alzayer and Sohrabi (2013)

Korrani et al. (2014)

Law and Sutcliffe et al. (2014)

Zeinijahromi et al. (2015)

HS recovery (%)

Figure V.

Alameri et al. (2015)

Dang et al. (2015)

Afekare and Sohrabi (2015)


Borazjani et al. Lee et al. (2017) (2017)

incremental oil recovery upon LSWF (%)

Reservoir simulation modelling results showing percentage incremental oil

recovery observed by multiple researchers in recent years. At reservoir scale, fines migration, MIE, geochemistry and wettability modification have been identified as major drivers of LSWF.100 118 38 99

103 39 40

Volume of produced formation water have also affected impact of

LSWF even in the presence of other mechanisms.

61

With a general positive LSWF outlook,

the only exception has been heavy oil reservoirs which are normally characterized with low


Page 49 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

recovery factors due to high viscosity and heavy metal contents.13, 73 Orange bars represent oil recovery by high salinity water while grey bars represent incremental oil recovery by LSWF Table IV. Percentage incremental oil recovery observed during different field implementations.

Author

Reservoir

Injected/Formation Incremental Oil Brine (ppm) recovery (% OOIP)

Webb et al.4

Sandstone

3,000/220,000

McGuire et

Sandstone (Alaska North Slope) 150-1500/15000

al.74

20--50 13

Robertson122

Sandstone (North 10,000/60,000; Semlek, West 3,304/42,000; Semlek, Moran) 7948/128,000

Recovery increases with formation/injection brine salinity ratio decrease

Patil et al.121

Sandstone (Alaska)

5,500/22,000

14

Seccombe et al.78

Sandstone (Alaska)

1467/22,000

Vledder et

Sandstone Isa)

al.123

Seccombe et al.93 Skrettingland al.111

(Omar,

Sandstone (Endicott)

9.5 10--15

2,200/9000 No information 13 available

et

No significant change

Sandstone (Snorre)

500/50,000

Thyne et al.126

Sandstone (Minnelusa)

No information No significant available change

Abdulla et al.124

Sandstone (Burgan)

5,000/140,000

Sandstone (Zichebashskoe)

No information 4 available

Zeinijahromi et

5.4

al.61

23.7

The Key Insights

Although major successes have been achieved in identifying some primary conditions and mechanisms underlying LSWF, observational discrepancies and limited field data makes


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 50 of 74

important the need for more advanced research on this EOR process. Further insights with adequate resources will do great deal to reduce - if not eliminate - controversies plaguing LSE and warrant more collaboration from industry to promote research. This section presents insights by introducing some areas which can expand the existing body of work in LSWF based on what has been reviewed.

5.4.1

Coherent and Systematic Studies of LSWF

Reservoir brine contain different complex ions, while typical reservoir crude oil consists of different components: from asphaltenes to resins to cyclic aromatics. On the other hand, majority of research conducted on low salt water injection have failed to systematic investigate specific ions (divalent and multivalent) and specific functional groups contained in this formation fluids, which has caused controversies in LSWF for a couple of decades. Thus, one approach to mitigating such is to examine the impact of specific brine ions and crude oil components at different scales while observing what mechanisms directly contribute to oil recovery.

5.4.2

Influence of Geochemistry and Geomechanics on LSWF

Darcy scale studies such as numerical simulation and laboratory research on LSWF conducted in the past have focused on capillary, gravity and viscous forces but with little or no geochemical (clay chemistry, brine chemistry, mineral dissolution) and geomechanical (e.g. natural or artificially induced fractures, pore roughness) considerations.12, 19 Reaction equations used in few geochemical simulations performed have been assumed rather than observed from experiments. Contact angle has been measured often on glass, mica and pure quartz surfaces with less account for pore roughness.58 Multiple fractured reservoirs have responded positively to LSWF in cases where unfractured clastic reservoirs have not, which might indicate an


Page 51 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

influence of fracturing on low salinity frontal displacement. Therefore, geochemistry and geomechanics should be incorporated in future research.

5.4.3

Use of Continental-shelf Fresh Water for LSWF

Person et al.127 evaluated feasibility of using continental shelf water as LSWF feed based on the recorded salinity of offshore freshwater in certain marine environments located in three oil producing basins: Gulf of Mexico, Niger Delta and North Sea. If the challenges such as volume of in-situ Low salt brines and production platforms are well managed, this will be of great utility to research and field implementation of not just LSWF, but other chemical flooding processes like Polymer flooding.

5.4.4

LSWF with Carbon Sequestration

Gulf of Mexico (GOM) offshore fields are quite crucial to the success of US petroleum industry, constituting 17% United States’ daily oil production currently.128 Oil production has experienced a steep decline for decades, but deep-water discoveries have helped to offset these declines. However, offshore deep-water production has now reached its peak, demanding urgent need for technically efficient and economically viable secondary and/or tertiary recovery techniques. Already, CO2-EOR is one of the leading enhanced displacement processes in the US: 300M bbls of oil per day was produced by CO 2 at the start of 2014, with 638M bbl/day in the forecasts for 2020. 129 Typical incremental CO2 recovery are between 5 and 25%.6, 129 In light of these, a hybrid technique can be explored: Low Salinity amplifiedCO2 recovery. A process which has great tendency to substantially recover billions of barrels proved oil reserves offshore GOM130, 131, Low salinity amplified-CO2 recovery integrates into the worldwide objective of promoting global warming through temporary carbon storage.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 52 of 74

Demands for freshwater which is increasingly getting scarce, being a primary resource for electricity production in the U.S are also lessened.

5.4.5

Influence of Reservoir Multi-layering on Recovery Efficiency of LSWF

Subsurface reservoirs consist of different layers of rock beds containing water, oil and gas. Based on geological deposition and saturation history, these multilayers exhibit different saturation profiles, different capillary pressures and thus relative permeability profiles. We also expect stratified salinity profiles from multi-layering. Consequently, flow patterns of waterflood processes through these sequences and brine salinities would vary across sequences. Since waterflood pattern and salinity reduction determine sweep efficiency, it will be inventive to examine how multi-layering impedes or supports the recovery technique, in this case LSWF.

6. CONCLUSION This paper provides a comprehensive review of LSWF through micro-scale and macro-scale investigations of oil/brine and crude/oil/brine systems. At both scales, different tools have been developed and utilized to examine multiple mechanisms –albeit controversial- underlying LSWF. Substantive incremental recovery has also been observed in most laboratory and computer simulation case studies. Some field projects have produced positive results but there is lack of interest from oil producers on a wide scale. This is due to inadequate understanding of mechanics of LSWF, controversies in existing conditions and mechanisms, unjustified correlation of numerous mechanisms to wettability alteration and insufficient investigation into other new mechanisms.

Statistical analyses show that wettability alteration is a leading effect in LSWF, and MIE, electrostatic interaction and polar component desorption can evidently influence the effectiveness of LSWF. Presence of high molecular weight crude oil polar components is


Page 53 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

crucial in recovery efficiency of LSWF but influence of non-polar compounds may not be discounted. Quantitative analyses of recovery efficiency reveal that outcrop sampling affect laboratory analyses, while presence or absence of clay and formation/injected water dilution factor do not always influence LSWF EOR. Following these, we propose few recommendations: coherent and systematic studies involving specific brine ions and oil functional groups; geochemical and geomechanical considerations; study of continental freshwater which already exists in strategic parts of oil producing basins like in the US and Offshore Niger-Delta in Nigeria; CO2-amplified low salinity waterflooding; and investigation of impact of multi-layering and stratified salinity profiles. Finally, LSWF is a low-cost and environmentally friendly EOR process. Existing controversies should motivate more advanced interdisciplinary research; and encouraging laboratory, simulation and field results are currently sufficient to attract investments from major oil producers.

AUTHOR INFORMATION

Corresponding Author Dayo Afekare Phone: (1)–832-768-1557; Email: [email protected] Author Contributions The manuscript was written through contributions of all authors. All authors have given approval to the final version of the manuscript.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Notes The authors declare no competing financial interest.

ABBREVIATIONS A = Area of model BPS = Bond Product sum CEC = Cation Exchange Capacity COBR = Crude Oil/Brine/Rock interactions DIW = De-Ionized Water DLE = Double Layer Expansion DLVO = Derjaguin, Landau, Verwey and Overbeek EDL = Electric Double Layer EOR = Enhanced Oil Recovery HSWI = High Salinity water injection LSE = Low Salinity Effects LSWF = Low Salinity Water flooding MIE = Multi-component Ion Exchange PNC = Pulse Neutron Capture SWCTT = Single Well Chemical Tracer Test


Page 54 of 74

Page 55 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

REFERENCES 1.

Clark, C. E.; Veil, J. A. Produced water volumes and management practices in United

States Environmental Science Division [Online], 2009. 2.

Majamaa, K.; Rosenberg, S.; Carlin, B. Managing Water in an Increasingly Demanding

Power Market 2016. 3.

Tang, G.-Q.; Morrow, N. R., Influence of brine composition and fines migration on

crude oil/brine/rock interactions and oil recovery. Journal of Petroleum Science and Engineering 1999, 24 (2–4), 99-111. 4.

Webb, K. J.; Black, C. J. J.; Al-Ajeel, H., Low Salinity Oil Recovery - Log-Inject-Log.

Society of Petroleum Engineers: 2004. 5.

Zhang, Y.; Xie, X.; Morrow, N. R., Waterflood Performance By Injection Of Brine

With Different Salinity For Reservoir Cores. In SPE Annual Technical Conference and Exhibition, Society of Petroleum Engineers: Anaheim, CA, USA, 2007. 6.

DOE/NETL. Produced Waters: Expansion of the CO2 Saline Storage Cost Model

Development of Cost Data for Water Production, Utilization and Disposal [Online], 2014. 7.

Burnett, D. Desalinating Brine from Oil and Gas Operations in Texas Southwest

Hydrology [Online], 2005, p. 25. 8.

Johnston, N.; Beeson, C. M., Water permeability of reservoir sands: Petroleum

development and technology. Trans. Am. Inst. Mining and Met. Engrs: 1945; Vol. 160, pp 4355.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

9.

Page 56 of 74

Sohrabi, M.; Mahzari, P.; Farzaneh, S. A.; Mills, J. R.; Tsolis, P.; Ireland, S., Novel

Insights Into Mechanisms of Oil Recovery by Use of Low-Salinity-Water Injection. 2017. 10. Hunter, R. J., Measurement of Electrokinetic Parameters. Zeta potential in colloid Science: 1981; pp 125-178. 11. Hornbrook, J.; Castanier, L.; Pettit, P., Observation of Foam/Oil Interactions in a New, High-Resolution Micromodel. In Proceedings of SPE Annual Technical Conference and Exhibition, 1991. 12. Kafili Kasmaei, A.; Rao, D. N., Is Wettability Alteration the Main Cause for Enhanced Recovery in Low-Salinity Waterflooding? 2015. 13. Afekare, D.; Sohrabi, M. Application of Low salinity water flooding to heavy oil reservoirs. Heriot watt University, 2015. 14. Mahani, H.; Keya, A. L.; Berg, S.; Nasralla, R., Electrokinetics of Carbonate/Brine Interface in Low-Salinity Waterflooding: Effect of Brine Salinity, Composition, Rock Type, and pH on ζ-Potential and a Surface-Complexation Model. 2017. 15. Greenwood, R.; Kendall, K., Selection of Suitable Dispersants for Aqueous Suspensions of Zirconia and Titania Powders using Acoustophoresi s. Journal of the European Ceramic Society 1999, 19 (4), 479-488. 16. Hilner, E.; Andersson, M. P.; Hassenkam, T.; Matthiesen, J.; Salino, P. A.; Stipp, S. L., The Effect of Ionic Strength on Oil Adhesion in Sandstone – The search for the Low Salinity Mechanism. Scientific Reports 2015, 5 (1). 17. Basu, S.; Sharma, M. M., Investigating the Role of Crude-Oil Components on Wettability Alteration Using Atomic Force Microscopy. 1999.


Page 57 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

18. Luxbacher, T., The Zeta Potential for Solid Surface Analysis: A practical guide to streaming potential measurement. first ed.; 2014. 19. Valluri, M. K.; Alvarez, J. O.; Schechter, D. S., Study of the Rock/Fluid Interactions of Sodium and Calcium Brines with Ultra-Tight Rock Surfaces and their Impact on Improving Oil Recovery by Spontaneous Imbibition. Society of Petroleum Engineers: 2016. 20. Mattax, C.; Kyte, J., Imbibition Oil Recovery from Fractured, Water-Drive Reservoir. . Society of Petroleum Engineers Journal 1962, 2 (2). 21. Dullien, F. Porous media 1979. 22. Egbogah, E. O.; Dawe, R. A., Spontaneous Emulsification Aspect Of Enhanced Oil Recovery. In Annual Technical Meeting, 1980. 23. Shariatpanahi, S. F.; Dastyari, A.; Bashukooh, B.; Haghighi, M.; Sahimi, M.; Farahani, F. J.; Ayatollahi, S. S. In Visualization Experiments on Immiscible Gas and Water Injection by Using 2D-Fractured Glass Micromodels., Proceedings of SPE Middle East Oil and Gas Show and Conference, 2005. 24. Sayegh, S.; Fisher, D., Enhanced Oil Recovery by CO Flooding in Homogeneous and Heterogeneous 2D Micromodels. Journal of Canadian Petroleum Technology 2009, 48 (8), 30-36. 25. Manlowe, D. J.; Radke, C. J., A Pore-Level Investigation of Foam/Oil Interactions in Porous Media. SPE Reservoir Engineering 1990, 5 (4), 495-502. 26. Mahers, E. G.; Wright, R. J.; Dawe, R. A., visualization of the behavior of EOR reagents in displacements in porous media. In European symposium on Enhanced Oil Recovery, 1981.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 58 of 74

27. Javadpour, F.; Fisher, D., Nanotechnology-Based Micromodels and New Image Analysis to Study Transport in Porous Media. Journal of Canadian Petroleum Technology 2008, 47 (2). 28. Jung, J.; Cao, S. C.; Shin, Y.; Al-Raoush, R. I.; Alshibli, K.; Choi, J. A microfluidic pore model to study the migration of fine particles in single-phase and multi-phase flows in porous media. Microsystem Technologies . [Online], 2017. 29. Fredriksen, S. B.; Rognmo, A. U.; Fernø, M. A., Pore-Scale Mechanisms During Low Salinity Waterflooding: Water Diffusion and Osmosis for Oil Mobilization. Society of Petroleum Engineers: 2016. 30. Bartels, W. B.; Rücker, M.; Berg, S.; Mahani, H.; Georgiadis, A.; Fadili, A.; Brussee, N.; Coorn, A.; van der Linde, H.; Hinz, C.; Jacob, A.; Wagner, C.; Henkel, S.; Enzmann, F.; Bonnin, A.; Stampanoni, M.; Ott, H.; Blunt, M.; Hassanizadeh, S. M., Fast X-Ray Micro-CT Study of the Impact of Brine Salinity on the Pore-Scale Fluid Distribution During Waterflooding. 2017. 31. Georgiadis, A.; Berg, S.; Makurat, A.; Maitland, G.; Ott, H., Pore-scale microcomputed-tomography imaging: Nonwetting-phase cluster-size distribution during drainage and imbibition. . Physical Review E 2013, 88 (3). 32. Jadhunandan, P. P.; Morrow, N. R., Effect of Wettability on Waterflood Recovery for Crude-Oil/Brine/Rock Systems. 1995. 33. Gatenby, W. A.; Marsden, S. S., Some W ettability Characteristics of Synthetic Porous Media. 1957. 34. Baptist, O. C.; Sweeney, S. A. Effect of Clays on the Permeability of Reservoir Sands to Various Saline Waters, Wyoming 1955.


Page 59 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

35. Lager, A.; Webb, K. J.; Black, C. J. J.; Singleton, M.; Sorbie, K. S., Low Salinity Oil Recovery - An Experimental Investigation. 2008a. 36. Sheng, J. J., Critical review of low-salinity waterflooding. Journal of Petroleum Science and Engineering 2014, 120, 216-224. 37. Akhmetgareev, V.; Khisamov, R., 40 Years of Low-Salinity Waterflooding in Pervomaiskoye Field, Russia: Incremental Oil. In SPE European Formation Damage Conference and Exhibition, Society of Petroleum Engineers: Budapest, Hungary, 2015. 38. Kazemi Nia Korrani, A.; Jerauld, G. R.; Sepehrnoori, K., Coupled Geochemical-Based Modeling of Low Salinity Waterflooding. Society of Petroleum Engineers: 2014. 39. Kazemi Nia Korrani, A.; Jerauld, G. R.; Sepehrnoori, K., Mechanistic Modeling of Low-Salinity Waterflooding Through Coupling a Geochemical Package With a Compositional Reservoir Simulator. SPE Reservoir Evaluation and Engineering 2016. 40. Lee, J. H.; Jeong, M. S.; Lee, K. S., Geochemical Modelling of Carbonated Low Salinity Water Injection CLSWI to Improve Wettability Modification and Oil Swelling in Carbonate Reservoir. In SPE Latin America and Caribbean Mature Fields Symposium . , 2017. 41. Bernard, G. G., Effect of Floodwater Salinity on Recovery Of Oil from Cores Containing Clays. Society of Petroleum Engineers: 1967. 42. Morrow, N.; Buckley, J., Improved Oil Recovery by Low-Salinity Waterflooding. Journal of Petroleum Technology 2011, 106-112. 43. Pu, H.; Xie, X.; Yin, P.; Morrow, N. R., Low-Salinity Waterflooding and Mineral Dissolution. Society of Petroleum Engineers: 2010.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 60 of 74

44. Loahardjo, N.; Xie, X. N.; Morrow, N. R., Oil Recovery by Sequential Waterflooding of Mixed-Wet Sandstone and Limestone. Energy & Fuels 2010, 24, 5073-5080. 45. Treiber, L.; Owens, W., A Laboratory Evaluation of the Wettability of Fifty OilProducing Reservoirs. Society of Petroleum Engineers Journal 1972, 12 (6), 531-540. 46. Morrow, N. R., Capillary Pressure Correlations For Uniformly Wetted Porous Media. Journal of Canadian Petroleum Technology 1976, 15 (4). 47. Chilingar, G. V.; Yen, T. F., Some Notes on Wettability and Relative Permeabilities of Carbonate Reservoir Rocks, II. Energy Sources 1983, 7 (1), 67-75. 48. Cuiec, L., Rock/Crude-Oil Interactions and Wettability: An Attempt To Understand Their Interrelation. . In SPE Annual Technical Conference and Exhibition . , 1984. 49. Ehrlich, R. In Wettability Alteration during Displacement of Oil by Water from Petroleum Reservoir Rock, 1974. 50. Strassner, J., Effect of pH on Interfacial Films and Stability of Crude Oil-Water Emulsions. Journal of Petroleum Technology 1968, 20 (3), 303-312. 51. Lowe, A.; Phillips, M.; Riddiford, A., On the Wetting of Carbonate Surfaces By Oil And Water. . Journal of Petroleum Technology 1973, 12 (2). 52. Madsen, L.; Ida, L., Adsorption of Carboxylic Acids on Reservoir Minerals From Organic and Aqueous Phase. 1998. 53. Johansen, R. T.; N., D. H., Relative Wetting Tendencies of Crude Oil by Capillarimetric Method. 1961.


Page 61 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

54. Shehata, A. M.; Nasr El-Din, H. A., Spontaneous Imbibition Study: Effect of Connate Water Composition on Low-Salinity Waterflooding in Sandstone Reservoirs. Society of Petroleum Engineers: 2015. 55. Austad, T.; Strand, S.; Madland, M. V.; Puntervold, T.; Korsnes, R. I., Seawater in Chalk: An EOR and Compaction Fluid. SPE Journal Paper 2008. 56. Austad, T.; Rezaeidoust, A.; Puntervold, T., Chemical Mechanism of Low Salinity Water Flooding in Sandstone Reservoirs. In SPE Improved Oil Recovery Symposium, Society of Petroleum Engineers: Tulsa, Okhlahoma, USA, 2010. 57. Morrow, N. R., Wettability and Its Effect on Oil Recovery. 1990. 58. Brady, P. V.; Morrow, N. R.; Fogden, A.; Deniz, V.; Loahardjo, N., Electrostatics and the low salinity effect in sandstone reservoirs. Energy & Fuels 2015, 29 (2), 666-677. 59. Kafili Kasmaei, A.; Rao, D. N., Is Wettability Alteration the Main Cause for Enhanced Recovery in Low- Salinity Waterflooding? In SPE Improved Oil Recovery Symposium, Engineers, S. o. P., Ed. Society of Petroleum Engineers: Tulsa, USA, 2014. 60. Merdhah, A. B. B.; Yassin, A. A. M., Scale Formation Due to Water Injection in Berea Sandstone Cores. Journal of Applied Sciences 2009, (9), 3298-3307. 61. Zeinijahromi, A.; Ahmetgareev, V.; Bedrikovetsky, P., Case Study of 25 Years of Low Salinity Water Injection. In SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition, 2015. 62. Ligthelm, D. J.; Gronsveld, J.; Hofman, J.; Brussee, N.; Marcelis, F.; van der Linde, H., Novel Waterflooding Strategy By Manipulation Of Injection Brine Composition. Society of Petroleum Engineers: 2009.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 62 of 74

63. Nasralla, R. A.; Alotaibi, M. B.; Nasr-El-Din, H. A., Efficiency of Oil Recovery by Low Salinity Water Flooding in Sandstone Reservoirs. Society of Petroleum Engineers: 2011. 64. Nasralla, R. A.; Nasr-El-Din, H. A., Double-Layer Expansion: Is It A Primary Mechanism of Improved Oil Recovery by Low-Salinity Waterflooding? Society of Petroleum Engineers: 2012. 65. Filoco, P. R.; Sharma, M. M., Effect of Brine Salinity and Crude Oil Properties on Relative Permeabilities and Residual Saturations. Society of Petroleum Engineers: 1998. 66. Jin, G.; Pérez, H. G.; Al Dhamen, A. A.; Ali, S. S.; Nair, A.; Agrawal, G.; Khodja, M. R.; Hussaini, S. R.; Jangda, Z. Z.; Ali, A. Z., Permeability Measurement of Organic-Rich Shale - Comparison of Various Unsteady-State Methods. Society of Petroleum Engineers: 2015. 67. Zarbov M; Brandon D; Cohen N; L., S., Engineering performance in applied EPD: problems and solutions. Journal of Material Science 2006, 41 (24), 8115–22. 68. Besra, L.; Liu, M., A review on fundamentals and applications of electrophoretic deposition (EPD). Progress in Materials Science 2007, 52 (1), 1-61. 69. Hanaor, D.; Michelazzi, M.; Leonelli, C.; Sorrell, C. C., The effects of carboxylic acids on the aqueous dispersion and electrophoretic deposition of ZrO2. Journal of the European Ceramic Society 2011, 32 (1), 235-244. 70. Sheng, J. J., Chapter 3 - Salinity Effect and Ion Exchange. In Modern Chemical Enhanced Oil Recovery, Sheng, J. J., Ed. Gulf Professional Publishing: Boston, 2011; pp 5178. 71. Omekeh, A. V.; Friis, H. A.; Fjelde, I.; Evje, S., Modeling of Ion-Exchange and Solubility in Low Salinity Water Flooding . In SPE Improved Oil Recovery Symposium. , 2012.


Page 63 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

72. Dang, C. T. Q.; Nghiem, L. X.; Chen, Z.; Nguyen, Q. P.; Nguyen, N. T. B., State-ofthe Art Low Salinity Waterflooding for Enhanced Oil Recovery. Society of Petroleum Engineers: 2013. 73. Alzayer, H.; Sohrabi, M., Numerical Simulation of Improved Heavy Oil Recovery by Low-Salinity Water Injection and Polymer Flooding. Society of Petroleum Engineers: 2013. 74. McGuire, P. L.; Chatham, J. R.; Paskvan, F. K.; Sommer, D. M.; Carini, F. H., Low Salinity Oil Recovery: An Exciting New EOR Opportunity for Alaska's North Slope. Society of Petroleum Engineers: 2005. 75. Schlumberger Oil Field Glossary. http://www.glossary.oilfield.slb.com/ (accessed July 15). 76. Lager, A.; Webb, K. J.; Black, C. J.; Singleton, M.; Sorbie, K. S., Impact of Brine Chemistry on Oil Recovery. In 14th EAGE Symposium on Improved Oil recovery, Cairo, Egypt, 2007. 77. Lager, A.; Webb, K. J.; Collins, I. R.; Richmond, D. M., LoSal Enhanced Oil Recovery: Evidence of Enhanced Oil Recovery at the Reservoir Scale. In SPE/DOE Improved Oil Recovery Symposium, Society of Petroleum Engineers: Tulsa, Okhlahoma, 2008b. 78. Seccombe, J. C.; Lager, A.; Webb, K. J.; Jerauld, G.; Fueg, E., Improving Wateflood Recovery: LoSalTM EOR Field Evaluation. Society of Petroleum Engineers: 2008. 79. Lager, A.; Webb, K. J.; Black, C. J. J.; Singleton, M.; Sorbie, K. S. In Low salinity oil recovery - An experimental investigation, Proceedings of International Symposium of the Society of Core Analysts, Trondheim, Norway, Trondheim, Norway, 2006.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 64 of 74

80. Sorbie, K. S.; Collins, I., A Proposed Pore-Scale Mechanism for How Low Salinity Waterflooding Works. Society of Petroleum Engineers: 2010. 81. Fjelde, I.; Asen, S. M.; Omekeh, A. V., Low Salinity Water Flooding Experiments and Interpretation by Simulations. Society of Petroleum Engineers: 2012. 82. Wolcott, J. M.; Groves, F. R., Jr.; Lee, H.-G., Investigation of Crude-Oil/Mineral Interactions: Influence of Oil Chemistry on Wettability Alteration. Society of Petroleum Engineers: 1993. 83. Emadi, A.; Sohrabi, M., Visual Investigation of Oil Recovery by LowSalinity Water Injection: Formation of Water Micro-Dispersions and WettabilityAlteration. Society of Petroleum Engineers: 2013. 84. Mahzari, P.; Sohrabi, M., Crude Oil/Brine Interactions and Spontaneous Formation of Micro-Dispersions in Low Salinity Water Injection. Society of Petroleum Engineers: 2014. 85. Tetteh, J. T.; Rankey, E.; Barati, R., Low Salinity Waterflooding Effect: Crude Oil/Brine Interactions as a Recovery Mechanism in Carbonate Rocks. Offshore Technology Conference: 2017. 86. Bai, J. M.; Fan, W. Y.; Nan, G. Z.; Li, S. P.; Yu, B. S., Influence of Interaction Between Heavy Oil Components and Petroleum Sulfonate on the Oil-Water Interfacial Tension. Journal of Dispersion Science and Technology 2010, 31 (4), 551-556. 87. Fjelde, I.; Omekeh, A. V.; Sokama-Neuyam, Y. A., Low Salinity Water Flooding: Effect Of Crude Oil Composition. Society of Petroleum Engineers: 2014.


Page 65 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

88. Fjelde, I.; Asen, S. M.; Omekeh, A.; Polanska, A., Secondary and Tertiary Low Salinity Water Floods: Experiment and Modelling. In EAGE Annual Conference & Exhibition incorporating SPE Europec, London, United Kingdom, 2013b. 89. Omekeh, A. V.; Friis, H. A.; Fjelde, I.; Evje, S., Modeling of Ion-Exchange and Solubility in Low Salinity Water Flooding In SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, 2012. 90. Ellila, G. Capillary Forces and Osmotic Gradients in Salt Water-Oil Systems. Trondheim, Norway 2012. 91. Fredriksen, S. B.; Rognmo, A. U.; Sandengen, K.; Fernø, M. A., Wettability Effects on Osmosis as an Oil-Mobilization Mechanism During Low-Salinity Waterflooding. 2017. 92. Sandengen, K.; Arntzen, O. J., Osmosis During Low Salinity WaterFlooding. In 17th European Symposium on Improved Oil Recovery, St. Petersburg, Russia, 2013. 93. Seccombe, J.; Lager, A.; Jerauld, G.; Jhaveri, B.; Buikema, T.; Bassler, S.; Denis, J.; Webb, K.; Cockin, A.; Fueg, E., Demonstration of Low-Salinity EOR at Interwell Scale, Endicott Field, Alaska. In SPE Improved Oil Recovery Symposium, Society of Petroleum Engineers: Tulsa, Okhlahoma, 2010. 94. Jadhunandan, P. P. Effects of Brine Composition, Crude Oil and Aging Conditions on Wettability and Oil Recovery. Ph.D. Dissertation, New Mexico Institute of Mining and Technology, Socorro, NM., 1990. 95. Al-adasani, A.; Bai, B.; Wu, Y.-S., Investigating Low Salinity Waterflooding Recovery Mechanisms in Carbonate Reservoirs. Society of Petroleum Engineers: 2012.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 66 of 74

96. Sánchez-Rodríguez, J.; Gachuz-Muro, H.; Sohrabi, M., Application of Low Salinity Water Injection in Heavy Oil Carbonate Reservoirs. In SPE EUROPEC 2015, Society of Petroleum Engineers: Madrid, Spain, 2015. 97. Anderson, W. G., Wettability Literature Survey – Part 2: Wettability Measurement. Journal of Petroleum Technology 1986, 1246-1262. 98. Schlumberger, Fundamentals of Wettability. Oilfield Review 2007, 44-60. 99. Alameri, W.; Teklu, T. W.; Graves, R. M.; Kazemi, H.; AlSumaiti, A. M., Experimental and Numerical Modeling of Low-Salinity Waterflood in a Low Permeability Carbonate Reservoir. Society of Petroleum Engineers: 2015. 100. Jerauld, G. R.; Webb, K. J.; Lin, C.-Y.; Seccombe, J. C., Modeling Low-Salinity Waterflooding. 2008. 101. Suijkerbuijk, B. M. J. M.; Sorop, T. G.; Parker, A. R.; Masalmeh, S. K.; Chmuzh, I. V.; Karpan, V. M.; Volokitin, Y. E.; Skripkin, A. G., Low Salinity Waterflooding at West Salym: Laboratory Experiments and Field Forecasts. Society of Petroleum Engineers: 2014. 102. Spagnuolo, M.; Callegaro, C.; Masserano, F.; Nobili, M.; Sabatino, R.; Blunt, M. J., Low Salinity Waterflooding: From Single Well Chemical Tracer Test Interpretation to Sector Model Forecast Scenarios. In SPE Improved Oil Recovery Conference . 2016. 103. Dang, C.; Nghiem, L.; Nguyen, N.; Chen, Z.; Nguyen, Q., Modeling and Optimization of Low Salinity Waterflood. Society of Petroleum Engineers: 2015. 104. S., S.; Cagatay, M. N.; Sanounah, A. M., Relationships Between Shale Content And Grain-Size Parameters In The Safaniya Sandstone Reservoir, Ne Saudi Arabia. Journal of Petroleum Geology 1996, 19.


Page 67 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

105. Shahin, A.; Tatham, R.; Stoffa, P.; Spikes, K., Optimal dynamic rock-fluid physics template validated by petroelastic reservoir modeling. Geophysics 2011, 76 (6). 106. Breeuwsma, A.; Wösten, J. H.; Vleeshouwer, J. J.; Slobbe, A. M.; Bouma, J., Derivation of Land Qualities to Assess Environmental Problems from Soil Surveys. Soil Science Society of America Journal 1986, 50 (1), 186. 107. Rivet, S.; Lake, L. W.; Pope, G. A., A Coreflood Investigation of Low-Salinity Enhanced Oil Recovery. In SPE Annual Technical Conference and Exhibition . , 2010. 108. Robbana, E.; Buikema, T. A.; Mair, C.; Williams, D.; Mercer, D. J.; Webb, K. J.; Hewson, A.; Reddick, C. E., Low Salinity Enhanced Oil Recovery - Laboratory to Day One Field Implementation - LoSal EOR into the Clair Ridge Project. Society of Petroleum Engineers: 2012. 109. Okasha, T. M.; Alshiwaish, A., Effect of Brine Salinity on Interfacial Tension in ArabD Carbonate Reservoir, Saudi Arabia. In SPE Middle East Oil and Gas Show Conference, Society of Petroleum Engineers: Kingdom of Bahrain, 2009. 110. Rotondi, M.; Callegaro, C.; Masserano, F.; Bartosek, M., Low Salinity Water Injection: eni’s Experience. Society of Petroleum Engineers: 2014. 111. Skrettingland, K.; Holt, T.; Tweheyo, M. T.; Skjevrak, I., Snorre Low Salinity Water Injection - Core Flooding Experiments And Single Well Field Pilot. Society of Petroleum Engineers: 2010. 112. Lee, S. Y.; Webb, K. J.; Collins, I.; Lager, A.; Clarke, S.; apos; Sullivan, M.; Routh, A.; Wang, X., Low Salinity Oil Recovery: Increasing Understanding of the Underlying Mechanisms. In SPE Improved Oil Recovery Symposium, Society of Petroleum Engineers: Tulsa, Oklahoma, USA, 2010.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 68 of 74

113. Shehata, A. M.; Nasr-El-Din, H. A., The Role of Sandstone Mineralogy and Rock Quality in the Performance of Low-Salinity Waterflooding. SPE Reservoir Evaluation & Engineering 2017. 114. Tang, G. Q.; Morrow, N. R., Salinity, Temperature, Oil Composition, and Oil Recovery by Waterflooding. 1997. 115. Winoto, W.; Loahardjo, N.; Morrow, N. R., Assessment of Oil Recovery by Low Salinity Waterflooding from Laboratory Tests. Society of Petroleum Engineers: 2014. 116. AlQuraishi, A. A.; AlHussinan, S. N.; AlYami, H. Q., Efficiency and Recovery Mechanisms of Low Salinity Water Flooding in Sandstone and Carbonate Reservoirs. In Offshore Mediterranean Conference and Exhibition, Ravenna, Italy, 2015. 117. Al-Attar, H. H.; Mahmoud, M. Y.; Zekri, A. Y.; Almehaideb, R. A.; Ghannam, M. T., Low Salinity Flooding in a Selected Carbonate Reservoir: Experimental Approach. In EAGE Annual Conference & Exhibition incorporating SPE Europec . 2013. 118. Law, S.; Sutcliffe, P. G.; Fellows, S. A., Secondary Application of Low Salinity Waterflooding to Forties Sandstone Reservoirs. Society of Petroleum Engineers: 2014. 119. Borazjani, S.; Behr, A.; Genolet, L.; Kowollik, P.; You, Z.; Bedrikovetsky, P., LowSalinity Fines-Assisted Waterflooding: Multiscale Analytical and Numerical Modelling. Society of Petroleum Engineers: 2017. 120. Attar, A.; Muggeridge, A. H., Evaluation of Mixing in Low Salinity Waterflooding. In SPE EOR Conference at Oil and Gas West Asia, 2016.


Page 69 of 74

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

121. Patil, S. B.; Dandekar, A. Y.; Patil, S. L.; Khataniar, S., Low Salinity Brine Injection for EOR on Alaska North Slope (ANS). . In International Petroleum Technology Conference . , 2008. 122. Robertson, E. P., Low-Salinity Waterflooding to Improve Oil Recovery-Historical Field Evidence. In S PE Annual Technical Conference and Exhibition, 2007. 123. Vledder, P.; Gonzalez, I. E.; Carrera Fonseca, J. C.; Wells, T.; Ligthelm, D. J., Low Salinity Water Flooding: Proof Of Wettability Alteration On A Field Wide Scale. Society of Petroleum Engineers: 2010. 124. Abdulla, F.; Hashem, H. S.; Abdulraheem, B.; Al-Nnaqi, M.; Al-Qattan, A.; John, H.; Cunningham, P. R. P.; Briggs, P. J.; Thawer, R., First EOR Trial using Low Salinity Water Injection in the Greater Burgan Field, Kuwait. Society of Petroleum Engineers: 2013. 125. Yousef, A. A.; Al-Saleh, S.; Al-Jawfi, M. S., Improved/Enhanced Oil Recovery from Carbonate Reservoirs by Tuning Injection Water Salinity and Ionic Content. Society of Petroleum Engineers: 2012. 126. Thyne, G. D.; Siyambalagoda Gamage, P. H., Evaluation Of The Effect Of Low Salinity Waterflooding For 26 Fields In Wyoming. Society of Petroleum Engineers: 2011. 127. Person, M.; Wilson, J. L.; Morrow, N.; Post, V. E. A., Continental-shelf freshwater water resources and improved oil recovery by low-salinity water flooding. In American Association of Petroleum Geologists, Geologists, A. A. o. P., Ed. 2017. 128. EIA Gulf of Mexico Fact Sheet. https://www.eia.gov/special/gulf_of_mexico/ (accessed October 31).


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 70 of 74

129. Teklu, T. W.; Alameri, W.; Graves, R. M.; Kazemi, H.; Al-sumaiti, A. M., Low-salinity Water-alternating-CO2 Flooding Enhanced Oil Recovery: Theory and Experiments. Society of Petroleum Engineers: 2014. 130. Koperna, G. J.; Ferguson, R. C., Linking CO2-EOR and CO2 Storage in the Offshore Gulf of Mexico. Offshore Technology Conference: 2011. 131. DOI, U.S. Bureau of Ocean Energy Management, Regulation and Enforcement. Outer Continental

Shelf,

Estimated

Oil

and

Gas

Reserves,

Gulf

of

Mexico. .

https://www.boem.gov/BOEM-2016-082/ (accessed October 31).

FOR TABLE OF CONTENT ONLY

LSWF Distinctive Study

Micro-scale investigations (oil/brine interactions, rock/oil/brine interactions)

Micromodellin g (μm to mm)

Coreflooding (mm to cm)

Zeta Potential (μm to mm)

Figure I.

Contact angle (μm to mm)

Macro-scale investigations (rock/oil/brine interactions)

Reservoir simulation (km)

Log-Inject-Log Test (feet)

Spontaneous imbibition (mm to cm)

SWCTT (feet)

Field implementation (km)

Process flow chart illustrating systematic investigation of LSWF. The length

scale of investigation is stated in brackets.


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Sequence of research procedure

Page 71 of 74

Geochemical simulation

Reservoir scale ( km to )

Coreflooding experiments

Core scale ( cm to m) Pore-network scale ( μm to mm)

Micromodelling

Atomic Force Microscopy/Zeta Potential Analyses

Atomic scale (nm to μm)

Figure II. An illustration of Systematic investigation of LSWF: at atomic scale we can delineate mechanisms that occur at mineral surfaces; next step is observation of multi-fluid flow patterns through complex rock-like porous media structure; the real rock core samples flooded by reservoir fluids subsequently displaced by LSWF at reservoir Temperature &Pressure are the most realistic lab experiments, but lack detail; finally reservoir modeling is capable of multiple physical scenarios under extended periods of time, predicting real-world applications, whose realism is based on verification from adequate reservoir characterization, field data and/or time resolved experiments.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 72 of 74

Percentage of selected reviewed papers (available in references section) that have identified LSWF mechansims from 1945 to 2017

Osmosis

pH

Fines migration with/without permeability reduction

Electrostatic interaction

Polar component desorption

MIE


0

10

20

30

40

50

60

70

80

90

Figure III. Statistical analyses of conditions and mechanisms identified with LSWF. All reviewed papers are available in references section. From Top to Bottom: Osmosis records low percentage because it has received least R & D efforts. pH has though been reported by many researchers but very few have directly correlated pH change with recovery increment during LSWF. Fines migration have long been in existence8 and is thus a popular mechanism but multiple field applications and Lab experiments have played down its influence in their observations. Electrostatic interaction, polar component desorption and MIE are mostly connected but with few exceptions. Finally, wettability alteration remains the most dominant mechanism being the most fundamental property that describes crude oil/rock/brine interactions.


Page 73 of 74

Incremental Oil Recovery during LSWF observed during Coreflooding of Outcrop and Actual Reservoir core samples Recovery efficiency (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

100 90

Small incremental recovery observed are due to: outcrop sampling and uncharacteristic clay structures Low pore size and high capillary pressure

80 70

Substantial difference in recovery factors for the same core is partly due to different dilution factors

60 50 40 30 20 10 0

HS Recovery (% OOIP)

Figure IV.

incremental oil recovery from HSWF (% OOIP)

Comparison of Percentage Incremental Oil Recovery observed during

Coreflooding of Outcrop and Actual Reservoir core samples. From Left to Right: Investigated outcrop samples showed very little improvements in oil recovery. Type of Clay (kaolinite) structures also affected recovery factor, though clay presence was not always necessary condition in this study.

Likewise, other mechanisms were responsible for Carbonates’

performance: sulfate content, electrostatic interaction and wettability improvement. Blue bars represent oil recovery by high salinity water while orange bars represent incremental oil recovery by LSWF.


Energy & Fuels

Reservoir Simulation Results Showing Incremental Oil Recovery of LSWF over HS brine Injection in Recent Years 100 Low incremental recovery was ascribed large produced Formation water prior to LSWF

90 80

Recovery efficiency

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 74 of 74

70 60 50


Low incremental recovery was ascribed to low rock permeability: 0.5mD-1.5mD


40 30 20 10 0 Alzayer and Sohrabi (2013)


Law and Sutcliffe et al. (2014)

Zeinijahromi et al. (2015)

HS recovery (%)

Figure V.

Alameri et al. (2015)

Dang et al. (2015)

Afekare and Sohrabi (2015)


Borazjani et al. Lee et al. (2017) (2017)

incremental oil recovery upon LSWF (%)

Reservoir simulation modelling results showing percentage incremental oil

recovery observed by multiple researchers in recent years. At reservoir scale, fines migration, MIE, geochemistry and wettability modification have been identified as major drivers of LSWF.100 118 38 99

103 39 40

Volume of produced formation water have also affected impact of

LSWF even in the presence of other mechanisms.

61

With a general positive LSWF outlook,

the only exception has been heavy oil reservoirs which are normally characterized with low recovery factors due to high viscosity and heavy metal contents. 13, 73 Orange bars represent oil recovery by high salinity water while grey bars represent incremental oil recovery by LSWF.


From Mineral Surfaces and Coreflood Experiments to Reservoir

Recommend Documents