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FINAL REPORT CONTENTS CD INFORMATION

Review of Low Salinity Water Flooding

Conducted for

DECC

By

David Hughes, Susanne Larsen and Rob Wright

Review of Low Salinity Water Flooding Conducted for

DECC

By

David Hughes, Susanne Larsen and Rob Wright

Final

A10DEC015A

October 2010

15 BON ACCORD CRESCENT ABERDEEN AB11 6DE United KingdomT: +44 1224 213440 F: +44 1224 213453 E: [email protected]

REGISTERED IN SCOTLAND SC 125513

Senergy (GB) Limited is also registered to OHSAS 18001

w w w . s e n e r g y w o r l d . c o m

15 BON ACCORD CRESCENT ABERDEEN AB11 6DE United KingdomT: +44 1224 213440 F: +44 1224 213453 E: [email protected]

REGISTERED IN SCOTLAND SC 125513

Senergy (GB) Limited is also registered to OHSAS 18001

w w w . s e n e r g y w o r l d . c o m

SENERGY (GB) LIMITED(A subsidiary of Senergy Oil & Gas Limited)

SENERGY (GB) LIMITED(A subsidiary of Senergy Oil & Gas Limited)


Author

David Hughes

Technical Audit

Gordon Adamson

Quality Audit

Verity Shaw

Release to Client

David Hughes

Date Released 6 December 2010

Senergy has made every effort to ensure that the interpretations, conclusions and recommendations presented herein are accurate and reliable in accordance with good industry practice and its own quality management procedures. Senergy does not, however, guarantee the correctness of any such interpretations and shall not be liable or responsible for any loss, costs, damages or expenses incurred or sustained by anyone resulting from any interpretation or recommendation made by any of its officers, agents or employees.

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Executive Summary DECC and NPD have agreed to cooperate in a joint investigation of EOR experience to date in both the UK and Norway sectors of the North Sea and further afield, drawing out successes and failures and the reasons for this. In the first instance concentrating on chemical EOR techniques (such as polymer, surfactants, gels and low salinity water flooding) which are considered to have the greatest potential for early application in North Sea fields.

As a first step in this collaboration, review studies are being undertaken covering (a) low salinity/hardness water flooding, (b) surfactants/alkaline (plus polymer for mobility control), (c) ‘weak gels’ also known as CDG/LPS and (d) “Bright Water” or “strong gels”.

This report covers low salinity/hardness water flooding.

The main conclusions to be drawn from this review are:

• Low salinity water flooding is an immature EOR technology but there does seem to be positive proof of field success. Uncertainty exists about the benefit with a suggested range of 0 to 12% OIIP.

• As yet there is no consensus of view on the mechanisms behind the process (i.e. what is causing the increase in recovery).

• As a consequence a priori prediction of which fields might be suitable and the potential incremental recovery in a given field is not possible, rather core floods and other laboratory studies are required followed by single well reactive chemical tracer tests (SWCTTs).

• A suitable source of low salinity water could be provided economically offshore from a combined nanofiltration and reverse osmosis processing plant or from a suitable shallow aquifer.

• Provision of a low salinity water supply in a field can act as a vanguard for other water based EOR processes such as polymer flooding, alkaline/surfactant/polymer flooding and linked polymer systems (LPS) with potential for even greater incremental recoveries. It can also overcome conventional problems such as souring and scaling.

• Although not yet proved, low salinity water flooding either alone or in conjunction with other water based EOR techniques has the potential to be a “game changer” in offshore reservoirs on a 3 to 8 year time frame.

It is recommended that:

• All fields where water flooding is ongoing or planned should be screened to determine the potential benefit of switching to low salinity water flooding. This should be undertaken systematically and consistently by independent laboratories using standard methodology. Such national screening programmes should be centrally organised but funded by operators. The opportunity should also be taken to extend this to systematic screening of the potential for other water based EOR techniques. A strategy is suggested to high grade the fields that should be the initial candidates for the screening.

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• The current experimental methodologies around low salinity water flooding should be refined and standardised. Experiments need to be carried out at reservoir conditions (including temperature, CO2 partial pressure and pH) using live crude, reservoir brine and native core with wettability conditions restored. Capillary end effects should be minimised and CT scanning or other techniques to record in situ residual oil saturation should be considered. Flow rates and pressure gradients need to be monitored and controlled during core testing and related to field inter-well gradients and rates. Uncertainties in core flood measurements need to be reliably assessed (random errors claimed to be below +/-1.5%, but systematic effects uncertain) in order to evaluate the significance of the improved oil recovery data. We estimate that at a basic level such a programme would cost between £10-20k per reservoir flow unit.

• DECC/NPD should initiate a study to investigate the costs of building and operating a combined nanofiltration/reverse osmosis plant on an offshore platform or on a reusable floating vessel.

• DECC/NPD should encourage operators to share more detailed information on their investigations and publish more data on oil composition, and injected and produced water compositions in SCAL experiments.

• DECC/NPD should ask operators to consider the economic benefits of low salinity water flooding ‘in the round’; i.e. it can also reduce souring and scale, yield cost savings on production chemicals and corrosion management, and reduce safety and environmental costs.

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Contents Executive Summary................................................................................................................... iii 1 Introduction...................................................................................................................... 1

1.1 Background to Joint DECC/NPD Study ............................................................... 1 1.2 Structure of Each Review .................................................................................... 1 1.3 Subject of This Report ......................................................................................... 2

2 Field Applications ............................................................................................................ 4 2.1 Endicott ................................................................................................................ 4 2.2 Omar Field ........................................................................................................... 6 2.3 Powder River Basin ............................................................................................. 7 2.4 Offshore Applications........................................................................................... 8 2.4.1 Heidrun ............................................................................................................ 8 2.4.2 Snorre .............................................................................................................. 9 2.5 Gullfaks .............................................................................................................. 10 2.6 Clair Ridge ......................................................................................................... 10

3 Low Salinity Water Flooding Recovery Mechanisms .................................................... 12 3.1 Overview ............................................................................................................ 12 3.2 Clays: Electronic Double Layer Ion Exchange Capabilities............................... 13 3.2.1 Clay Structure................................................................................................ 13 3.2.2 Double Layer Expansion ............................................................................... 15 3.2.3 Ion Exchange................................................................................................. 16 3.3 In-Situ Osmosis.................................................................................................. 17 3.4 IFT Reduction .................................................................................................... 17 3.5 Wettability Alterations ........................................................................................ 17 3.5.1 Multicomponent Ion Exchange (MIE) Mechanism......................................... 18 3.5.2 pH Induced Desorption of Organic Material .................................................. 19 3.6 Discussion of Recovery Mechanisms ................................................................ 19

4 Chemical and Environmental Aspects .......................................................................... 22 4.1 Offshore Production of Low Salinity Water ........................................................ 22 4.2 Costs .................................................................................................................. 23 4.3 Environmental Issues......................................................................................... 23

5 Screening Criteria.......................................................................................................... 24 5.1 Clay.................................................................................................................... 24 5.2 Ion Composition of the Injected Water............................................................... 25 5.3 Oil Composition.................................................................................................. 25 5.4 Wettability .......................................................................................................... 25 5.5 Ranking of Fields for Low Salinity EOR Potential.............................................. 26

6 Conclusions and Recommendations............................................................................. 29 6.1 Conclusions ....................................................................................................... 29 6.2 Recommendations ............................................................................................. 29

7 References .................................................................................................................... 31

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List of Tables Table 2.1: Endicott Water Analysis (2 SWCTTs were carried out in Well 3-39A) ..................... 4 Table 2.2: Water Compositions (g/l) for Snorre....................................................................... 10 Table 3.1: Overview of Suggested Low Salinity Water Flooding Mechanisms ....................... 12 Table 3.2: Clay Properties ....................................................................................................... 14 Table 5.1: Possible Criteria to Rank Fields for Low Salinity Water Flooding Potential ........... 27

List of Figures Figure 2.1: Endicott Pilot Area (Sub Zone K3A-2)..................................................................... 5 Figure 2.2: Endicott Pilot Oil Rate and Watercut Response...................................................... 5 Figure 2.3: Laboratory and Single Well Test Results of Low Salinity Incremental Recovery versus Clay Content .................................................................................................................. 6 Figure 2.4: Water Saturation Response from Buckley Leveret Theory for High Salinity and Low Salinity Flooding in an Oil Wet System.............................................................................. 7 Figure 2.5: Oil and Water Production (top) and Watercut Development (bottom) for OMA125 Showing Behaviour Consistent with Buckley-Leverett Theory.................................................. 7 Figure 2.6: Recovery Factor in Minnelusa Reservoirs as a Function of Salinity Ratio ............. 8 Figure 2.7: Low Salinity Water Flooding in Heidrun .................................................................. 9 Figure 2.8: Low Salinity Water Flooding Pilot in Upper Tilje Formation, Heidrun ..................... 9 Figure 3.1: Tetrahedral – Octahedral Clay Structure (Class 1:1)............................................ 13 Figure 3.2: Surface Charge of Three Clays as a Function of pH ............................................ 14 Figure 3.3: Schematic of Electric Double Layer in High and Low Salinity Environments ....... 15 Figure 3.4: Schematic of Capillary Pressure at Curved Oil/Water Interface ........................... 20 Figure 3.5: Schematic of Trapped Oil Ganglion ...................................................................... 20 Figure 4.1: Flow Schematic of Shell’s Designer Water Process ............................................. 22 Figure 5.1: Intermediate/Oil Wet (left) and Water Wet (right) Relative Permeabilities used in Simulation ................................................................................................................................ 28 Figure 5.2: Response to Wettability Change on Cumulative Recovery and Watercut............ 28

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1 Introduction

1.1 Background to Joint DECC/NPD Study

DECC officials have been in discussion with their NPD counterparts about potential areas for cooperation in Enhanced Oil Recovery (EOR). Both DECC and the NPD are concerned that there is a decreasing “window of opportunity” to implement EOR projects in the increasingly mature oil reservoirs of the North Sea and both have implemented initiatives to stimulate new investment in EOR. DECC and NPD agree that increased cooperation between the UK and Norway would help in understanding what might make EOR work in the North Sea on a more significant scale than heretofore and in identifying the levers to deliver future EOR projects.

DECC and NPD have agreed to cooperate in a joint investigation of EOR experience to date in both the UK and Norway sectors of the North Sea and further afield, drawing out successes and failures and the reasons for this. In the first instance concentrating on chemical EOR techniques (such as polymer, surfactants, gels and low salinity water flooding) which are considered to have the greatest potential for early application in North Sea fields.

Information obtained from the review will be used to compile an EOR “toolkit” covering the application of chemical EOR techniques to North Sea reservoirs. To date chemical EOR has generally been applied in isolation, one treatment at a time in a single field, and there is often little long term learning from the applications. NPD have been pioneering a more integrated approach to EOR, looking at the potential to combine two or more EOR techniques at the same time and/or in more than one reservoir. This work suggests that combining EOR interventions in a more structured way can significantly increase incremental reserves with only a comparatively modest increase in overall project risk.

As a first step in this collaboration, review studies are being undertaken covering (a) low salinity/hardness water flooding, (b) surfactants/alkaline (plus polymer for mobility control), (c) ‘weak gels’ also known as CDG/LPS and (d) “Bright Water” or “strong gels”.

1.2 Structure of Each Review

Each review will aim to gather information and report within the following structure:

Background of process (i.e. its origins).

Major field applications (details of field deployments and supporting lab work) covering last ~10 years worldwide and any offshore applications in last ~20 years.

Any ongoing or recent laboratory studies in relation to offshore applications not yet implemented.

How does the process work?

What are the leading chemicals?

• Who are the leading vendors of process/suppliers of chemicals and delivery form (power, concentrate, emulsion, etc.)?

• What facilities are required to mix and inject chemicals?

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• How much is required?

• What concentrations are required for field application?

• Amount required per incremental barrel?

• How much do they cost?

• What is their environmental ranking?

Screening criteria

• How do we identify suitable fields?

• What experiments do we need to do?

• What single well tests do we need to do?

List of publications relating to process.

What are the factors that are preventing deployment offshore at present?

Are there any showstoppers preventing offshore application?

1.3 Subject of This Report

This report is about a recent development in water flooding usually termed “low salinity water flooding” where particular attention is paid to the ionic content of the water.

BP have applied for an international patent under the trademark LoSal (Lager, 2006-8) and Shell have outlined a production train for low salinity/hardness applications where various production and reject streams are combined from a nanofiltration plant followed by a reverse osmosis plant (Ayirala, 2010), and trademarked the term “Designer Water”. The term “smart water” has also been used in a similar context in relation to water injection in chalk fields (Austad, 2008). In this report the process will be referred to as low salinity water flooding and the scope of the review will be restricted to clastic reservoirs.

The salinity and ionic composition of injected water have not been a major concern within the oil production industry except perhaps with regard to scaling and reservoir souring potentials (and in relation to optimising the performance of surfactant flooding). It has, however, been known for decades that the ionic strength of a fluid flowing in a porous medium does influence the measured permeability (Schleidegger, 1974). Conventionally the nearest available supply of water has been used for water flooding which for offshore applications usually means seawater and laboratory experiments for offshore applications are normally conducted using (synthetic) reservoir brine or seawater.

In the 1990s, Norman Morrow and co-workers at the University of Wyoming published core flood results that indicated that injecting low salinity water leads to increased oil production compared to injecting high salinity (sea)water (Tang, 1999). Since then many experiments have been carried out with some showing improved recovery and some with no additional recovery (Zhang, 2007); also with some showing the effect in both secondary and tertiary mode and some only in secondary mode (Rivet, 2009). The major evidence for low salinity



benefits therefore comes from core flood tests, whilst the uncertainties in, and reliability of, the data obtained have not always received proportional attention. Field evidence is now beginning to be gathered from single well tests using reactive tracer tests to evaluate saturation changes, and field pilots.

Various theories have been presented to explain how the process works but so far there is no unanimity of view. These theories, of course, are important in the search for the screening criteria that could help us to predict the reservoirs where the method would have the best chance of working.



2 Field Applications

2.1 Endicott

The first comprehensive inter-well field trial of low salinity water flooding took place during 2008-9 in BP’s offshore Endicott field on the North Slope of Alaska (Seccombe, 2010).

Endicott is the third largest North Slope field with estimated oil in-place of around a billion barrels. It was brought on stream in 1987 and has been produced by gas re-injection at the crest and seawater injection around the periphery. The salinity and hardness of the reservoir brine and the injected seawater are approximately equal (Table 2.1 from McGuire, 2005).

Table 2.1: Endicott Water Analysis (2 SWCTTs were carried out in Well 3-39A)

The original results, which prompted the trial were four single well tests with the saturation change measured using reactive chemical tracer tests (SWCTTs) undertaken in the Prudhoe Bay and Endicott fields (McGuire, 2005) which indicated that the incremental oil recovery from low salinity water injection was in the range 6-12% OIIP. Subsequent laboratory and simulation work, and further single well tests, both using both log-inject-log and SWCTTs to measure saturation changes was also positive (Jerauld, 2006; Webb, 2008; Seccombe, 2008).

SWITTs indicated that the residual saturation to high salinity water flooding is 41% reducing to 27% if low salinity water is used, giving an incremental recovery of 15% OIIP (Swi is 5%) which would obviously be lower when areal and vertical sweep effects are accounted for.

The field trial used a single injector–producer pair with an inter-well spacing of 1040ft (Figure 2.1). It was undertaken in the K3A-2 sand which has thickness 30-45 ft (isolated above and below by shales), porosity 20% and permeability 100 mD (established by pressure pulse tests). Clay content was 12% with kaolinite being the dominant clay followed by illite. Clearly by comparison with North Sea fields the residual saturation of high salinity water flooding at 41% is high and the inter-well spacing at 1040 ft is low.

The trial area was flooded using high salinity water to 95% watercut, followed by 10 months (1.6 pore volumes) of reduced salinity water injection (trucked from a gravel pit nine miles away).with a final high salinity postflush.



Figure 2.1: Endicott Pilot Area (Sub Zone K3A-2)

After about two months an increase in oil rate and a reduction in watercut were observed with the increase in oil rate immediately followed by the arrival of reduced salinity water (Figure 2.2). The oil response was as predicted (from core floods and single well tests) but the drop in watercut (95 to 93%) was less than expected. Analysis of ionic content of the produced water showed that 45% of produced water was coming from outside the pilot area. Backing out production from outside the pilot area (details of how this was achieved in Seccombe, 2010) it was estimated that the effective drop in watercut within the pilot area was 5.5%.

Figure 2.2: Endicott Pilot Oil Rate and Watercut Response

Although no iron was present in the formation or injected waters, there was a sharp increase in iron production from non detectable amounts to 3-4 ppm corresponding to the sharp decrease in water cut (and arrival of the first low salinity tracer injected at start of reduced salinity flood). BP believe this confirms the multi-component ion exchange (MIE) theory of low salinity water flooding (see Section 3.5.1). They postulate that the iron coats the kaolinite binding the polar molecules in the oil to the clay but these bridges are removed by the reduced salinity water releasing polar compounds and free iron.



Figure 2.3: Laboratory and Single Well Test Results of Low Salinity Incremental Recovery versus Clay Content

Analysis of the results in the pilot area by comparison with the estimated results of continuing high salinity water flooding indicate an incremental recovery of 10% OIIP by the start of the high salinity postflush. Previous core floods and single well tests showed a 13% incremental recovery for a formation with a 12% clay content (Figure 2.3) (Seccombe, 2008) so the result is broadly in line when area and vertical sweep effects are taken into account

Overall this has been a very useful test of low salinity water flooding in the field and given the success is likely to be followed by further trials.

2.2 Omar Field

A detailed analysis of secondary low salinity water flooding in the Omar Field in Syria operated by Al Furat (a Shell subsidiary) has been undertaken (Vleddar, 2010). This is one of the few documented proofs of the concept of low salinity water flooding on a reservoir scale.

The light oil (µ=0.3 cp) field came on stream in 1989 but experienced rapid pressure loss indicating absolute lack of aquifer support. Water flooding using a river water source with salinity 500 mg/L (<<100 mg/L bivalent ions) began in 1991. The formation water has a salinity of 90000 mg/L with a high content of bivalent ions (5000 mg/L) and the clay content is 0.5-4% of which 95-100% is kaolinite.

Special core analysis and low rate core flood measurements showed that the native state wettability in Omar was oil wet (wettability index of 1). Spontaneous imbibition experiments showed additional recovery from low salinity brine subsequent to high salinity brine correlating with kaolinite content (incremental recovery up to 24% PV). Similar laboratory results were also obtained in an analogue field (Isba) where a log-inject-log test in a watered out well showed that a wettability reduction from 1 to 0.2-0.4 had occurred as a result of the low salinity water flooding.

Logs in Omar show an initial oil saturation of 95% and remaining oil saturation after low salinity water flooding of 15% (but with uncertainty in range the 10-30% as the calculation is very sensitive to the salinity used in determining the saturation from the logs). During intermediate stages of the flood, log interpretations at well OMA125 confirm the dual-step watercut development predicated by Buckley-Leverett theory (Lake, 1989), with an initial



modest reduction in oil production accompanied by miscibly displaced formation water (Figure 2.4 and Figure 2.5).

Figure 2.4: Water Saturation Response from Buckley Leveret Theory for High Salinity and Low Salinity Flooding in an Oil Wet System

Figure 2.5: Oil and Water Production (top) and Watercut Development (bottom) for OMA125 Showing Behaviour Consistent with Buckley-Leverett Theory

In the Al Furat (and Shell) view is that the measurements and observations at 21 wells in Omar present abundant proof of wettability alteration occurring at the reservoir scale. Analysis indicates that the change in wettability is probably from 0.8-1.0 to 0.2 which would give an expected incremental oil recovery of 17% OIIP (compared to high salinity water flooding). However, comparison of high and low salinity water flooding across Al Furat’s assets indicates that a more conservative estimate would be an increase in 5-15% STOIIP from low salinity water flooding in Omar.

2.3 Powder River Basin

In the Powder River basin of Wyoming numerous fields have been flooded with water from low salinity sources (Robertson, 2007). Following a trawl of the data available in public records, the waterflood responses in three Minnelusa formation fields, namely; West Semlek, North Semlek and Moran were deemed to have the best records and analysed.

Ultimate recoveries from the three fields were plotted as a function of the ratio of the average salinity of the injection water divided by the salinity of the formation water (Figure 2.6) indicating a trend to a higher recovery factor with a lower salinity ratio.



However, the review and this conclusion come with lots of caveats. The public records relating to the fields are far from complete and there is an indication that polymer had been used at some time to increase recovery in all three fields (oil viscosity ~15cP).

The field results tend to corroborate laboratory core flood results using Minnelusa crude, brine and diluted bride (although the experiments used Berea outcrop material rather than Minnelusa formation) but “should not be considered proof positive”.

Figure 2.6: Recovery Factor in Minnelusa Reservoirs as a Function of Salinity Ratio

2.4 Offshore Applications

The Endicott field case is the only reported tertiary inter-well application of low salinity water flooding so far and no offshore implementation has yet been carried out. However for some Norwegian Continental Shelf fields, laboratory work and SWCTTs have been carried out over the last few years. Statoil have indicated that Heidrun, Snorre and Gullfaks are all being considered for a possible low salinity pilot (Spangenberg, 2008).

2.4.1 Heidrun

A number of reservoir temperature core floods using various outcrop rock samples and Heidrun stock tank oil have been undertaken (Heigre, 2008). The floods were undertaken using seawater, a mixture of 10% seawater and 90% fresh water, and a mixture of 1% seawater and 99% fresh water. The flooding sequence is not clear, but it is likely there is a combination of secondary and tertiary flooding experiments. Figure 2.7 shows the residual saturation to water flooding as a function of seawater percentage for various experiments. The precise reason for the large ranges is not clear. However, taking the middle of the ranges shown, the residual oil saturation reduces from 27% (seawater) to 22% (10% seawater) to 18% (1% seawater); the average reduction is 9 percentage points. There is no information about the individual core floods, and a different number of points are plotted at each salinity (so it is not possible to understand, for instance, if the highest saturation in the black points corresponds to the highest saturation in the red points, etc).

It is likely that some of the variation is caused by the effect of the different outcrop cores used. Although the mechanisms by which low salinity water flooding works are not yet satisfactorily understood, rock surface properties and chemistry play an important role in the process (see Section 3) so it is difficult to deduce from these experiments that the process will work in Heidrun. It is understood that a low salinity single well tracer test (SWCTT) was undertaken in Heidrun in late 2009, but no results have been published so far.



Figure 2.7: Low Salinity Water Flooding in Heidrun

Heigre, 2008 does not mention the SWCTT but presents details of a proposed low salinity pilot in Heidrun. The proposal is to add a demonstration reverse osmosis (RO) plant to the existing sulphate removal plant (capacity 32 km3/d) to produce 4 km3/d of low salinity water (<500 ppm TDS, <40 ppm sulphate, <5 µm filtration). Low salinity water will be injected into two wells (A25 and A17) in the Lower Tilje Formation, with response expected in three producers (A10, A14 and A28) – see Figure 2.8. As of May 2008 there were bullish plans to implement this pilot project by late 2009/early 2010, but it is understood the plans have been delayed.

Figure 2.8: Low Salinity Water Flooding Pilot in Upper Tilje Formation, Heidrun

2.4.2 Snorre

A comprehensive set of experiments using Snorre core material (Upper Statfjord, Lower Statfjord and Lunde), oil and formation water and flooding with various salinity and divalent cation concentrations showed negligible benefit compared to high salinity water flooding. This, even though the mineralogy was similar to other clastic systems where low salinity water flooding has shown a positive response (Skrettingland, 2010).



Nevertheless, Statoil carried out a single well reactive tracer test (SWCTT) in 2009 after completion of the core experiments. However, this also showed no significant reduction in oil saturation (Skrettingland, 2010).

Compared to Endicott the residual oil after water flooding in Snorre is below 25% so the wettability, or other relevant conditions, would appear to be more favourable to seawater injection than in Endicott. This obviously lowers the potential additional benefit from low salinity water flooding. The formation water salinity in Snorre is similar to Endicott, although in Endicott the divalent cations (Ca, Mg) are significantly lower (compare Table 2.2 with Table 2.1).

Table 2.2: Water Compositions (g/l) for Snorre

As for Endicott, the dominating clay in Snorre is kaolinite, varying (in the main) between 8 and 18%. From the Endicott clay content versus additional recovery correlation (Figure 2.3), this would mean an additional recovery upward of 9% OIIP, far from what is seen in the Snorre experiments and SWCTT.

The kaolinite content in the 1 m sand used in the SWCTT would appear to be highly variable with recorded amounts of 14.7% and 1.2% in two cores only 0.5 m apart so it would not be expected that this well would be favourable to low salinity water flooding. Other mineralogy differences are also apparent between the field cores and the SWCTT well (plagioclase content and mica/illite content) making comparison between the laboratory and field results difficult.

Skrettingland, 2010 also contains a good review of the many conflicting results from experiments in relation to the role of wettability, clays and oil composition. In particular the conflicting evidence in relation to the direction of wettability change with some researchers finding that a successful low salinity water flood requires the wettability to be changed from water-wet to mixed-wet whilst others find the reverse.

2.5 Gullfaks

Statoil report that laboratory tests of low salinity water flooding in Gullfaks core are “highly encouraging”, and further studies and a possible pilot test are under consideration (Talukdar, 2008).

2.6 Clair Ridge

BP is implementing secondary low salinity water flooding in the second phase of development at the Clair field, known as Clair Ridge (Mair, 2010 and BP, 2010). 145,000 b/d of injection



water will be supplied by a desalination unit fed by treated and filtered seawater. Early in field life the low salinity water would be mixed with produced water for reinjection. In later field life when the produced water rate exceeds requirements it will be disposed of via dedicated disposal wells.

Mair, 2010 presents a very useful timeline of the history of low salinity flooding research and a strategy for appraising the appropriateness of low salinity water flooding for a particular field.

Overall BP estimate that implementing low salinity water flooding in Clair Ridge will produce 7% OIIP more than conventional seawater flooding at a development cost of $3 per barrel.



3 Low Salinity Water Flooding Recovery Mechanisms

3.1 Overview

Although demonstrated in the laboratory and in field tests, how low salinity water flooding works, i.e. the mechanisms that give rise to incremental recovery, are not well understood. A useful review of the various explanations and controversies can be found in (Rivett, 2009).

Table 3.1 summarises the mechanisms that have been suggested. These have been divided into types in the table according to which flow parameter they are addressing.

Effect type Mechanism Short Explanation Main reference

Contra indications

Pressure/ permeability

Osmosis Distributed clays separating brines with different salinities create an additional (osmotic) pressure that enhances the water drive.

Buckley, 2009 Low salinity water flooding does not seem to work for mineral oil. (Rivet, 2009)

Pressure/ permeability

Clay particle (fines) movement

Due to the expansion of the electric double layer (and maybe also ion exchange) clay particles and other mixed-wet fines are removed from the rock surface at low salinity conditions leaving a water wet spot. The migrating fines might block narrow pore throats and cause microscopic diversion of the injected water.

Tang, 1999 Fines migration has sometimes been observed in low salinity core flooding but BP claim never to have seen this (Lager, 2006), Also refuted by (Rivett, 2009)

IFT reduction Alkaline flooding behaviour

pH rises during low salinity flood high enough to saponicate certain components of the oil. Thereby lowering the interfacial tension between water and oil (in a similar way to alkaline flooding).

Buckley, 2009 pH increase is not seen in all experiments and is usually not as high as in alkaline flooding. (Buckley, 2009; Zhang, 2006)

IFT reduction “Salt-in” effect The charged oil components on the surfaces of the clays are easier to desorb and dissolve in the water phase; “salt-in” effect. The loosened particles lower the interfacial tension between water and oil like surfactant flooding.

Austad, 2008 This potential mechanism has not been widely discussed. Austad suggested experiments to check the theory which led to the pH induced ion exchange theory (Austad, 2010)

Wettability change

Multicomponent Ion Exchange (MIE)

Due to expansion of the electric double layer and cation exchange capacity of the clay complex, bound charged organic components of the oil are substituted by Ca2+ leading to an increase in the water wetness of the formation.

Lager, 2006-8; Ligthelm, 2009

Low salinity brines without Ca2+ and Mg2+ ions have been seen to increase recovery (Tang, 1999; Austad, 2010)

Wettability change

pH driven The cation exchange capacity of the clays is triggered by near surface pH changes brought about by protons substituting Ca2+ on the clay surfaces in low salinity water flooding.

Austad, 2010 No contra indications published yet, as the theory was first presented in April 2010

Table 3.1: Overview of Suggested Low Salinity Water Flooding Mechanisms



Apart from the electro- and pressure-osmosis explanations, all mechanisms involve chemical reactions at the rock-fluid interface that lead to wettability changes. This means that all the methods, except osmosis, could have been placed in the “alteration of wettability” category.

The first explanation of the mechanism (Tang, 1999) involved loosening of clay particles from the surface leaving a water wet spot. The migrating clay particles are then thought to block the narrowest pore throats diverting the water to the larger oil-filled pores (in a similar way to the explanation of how linked polymer systems (LPS) work), so this mechanism appears in the pressure/permeability category.

The suggested low salinity wettability altering mechanisms all involve the electric double layer formed at charged rock and clay surfaces, and the ion exchange capability of clays so these phenomena are briefly described in Section 3.2 before a closer look at the mechanisms from Table 3.1. More comprehensive descriptions of clays and clay-water interactions can be found in ground water literature, e.g. Lower, 1996; Kehew, 2001.

3.2 Clays: Electronic Double Layer Ion Exchange Capabilities

3.2.1 Clay Structure

Clays are built from layers (sheets) of SiO4 tetrahedrons and octahedrons like Al2(OH)6)n or

((Fe or Mg)3(OH)6)n. They are divided into types:

1:1 where the clay mineral consists of one octahedral sheet and one tetrahedral sheet

2:1 where the clay mineral consists of one tetrahedral sheet between two octahedral sheets

Figure 3.1: Tetrahedral – Octahedral Clay Structure (Class 1:1)

Clays get their permanent surface charge from substitution of the cations, e.g. substitution of

Si4+ by Al3+ in the tetrahedral and substitution of Al3+ by for instance Fe2+ in the octahedral units. Usually the surface charge (zeta potential) is negative. The type and surface charge of some common clays are given in Table 3.2.



Group Clay Type pHzpc CEC meq/100g

Permanent Surface charge

kaolin kaolinite 1:1 4.6 3-15 no permanent

charge

non-swelling

kaolin dickite

kaolin halloysite swelling

kaolin nacrite

smecite montmorillonite 2:1 2.5 80-120 negative swelling

smecite nontronite 2:1

smecite saponite 2:1

illite illite 2:1 20-50 negative non-swelling

chlorite various: 2:1 10-40 positive non-swelling

vermiculite (trioctahedral)

100-200 swelling

vermiculite (dioctahedral)

10-50

Table 3.2: Clay Properties

Kaolinite is a 1:1 clay with very little fixed negative surface charge (Kehew, 2001). The charge on kaolinite develops due to complexation reactions and is pH dependent. So below a pH threshold the whole kaolinite surface is positive; above the threshold the kaolinite surface is negative. At the threshold, the so called pH at zero potential concentration, pHzpc, the surface is neutral (Table 3.1).

Figure 3.2: Surface Charge of Three Clays as a Function of pH



Figure 3.2 shows the surface charge in meq/100g of kaolinite, illite and montmorillonite for various pH values. The charge on permanently charged clays is seen to be much bigger than the pH induced surface charge. This also means that the ion exchange capacity of the permanently charged clays is bigger and less pH dependent than for kaolinite (see Section 3.2.3).

Kaolinite does, however, have high surface charge density as its specific surface area is considerably lower than other clays. Also its crystal surfaces differ, where the basal (or platelet “face”) surface charge is regarded as constant and due to substitution, while the particle edge charge is subject to protonation/deprotonation of surface hydroxyl groups and so is highly pH sensitive (see e.g. Schroth, 1997; Zhou, 1992).

3.2.2 Double Layer Expansion

The charged surface of a rock or clay attracts ions of the opposite charge in the water phase. In this way the charged double layer that gives rise to the zeta potential is formed. Various theories and description of the profile of the potential moving away from the surface exists (Kehew, 2001). Here we stick to the simple illustration in Figure 3.3.

The thickness of the double layer is related to the concentration of ions in the water phase and the charge of the ions, ne, by the following equation:

[ ] enionsThickness∝ 1

This means that the double layer expands in low salinity water compared to high salinity water. Expansion of the double layer can also explain the swelling of some clays in fresh water. Swelling properties are listed in Table 3.2.

The above equation also implies that for the same concentration, divalent cations such as Ca2+ decrease the thickness of the double layer more than monovalent ions like Na+.

Ca2+ Na+ Na+ Na+ Na+ Ca2+ Na+ Na+ Na+ Na+ Na+ Ca2+ - - - - - - - - - - - - - - - - - - - - - - - - -

- - - - - - - - - - - - - - - - - - - - - - - - -

Ca2+ Na+ Na+ Na+ Na+ Ca2+ Na+ Na+ Na+ Na+ Na+ Ca2+

d

d

Low Salinity

[ ] enionsdThickness 1∝=




d


- - - - - - - - - - - - - - - - - - - - - - - - - d


- - - - - - - - - - - - - - - - - - - - - - - - - d


d


High Salinity

Ca2+ Na+ Na+ Na+ Na+ Ca2+ Na+ Na+ Na+ Na+ Na+ Ca2+ - - - - - - - - - - - - - - - - - - - - - - - - -

- - - - - - - - - - - - - - - - - - - - - - - - -

Ca2+ Na+ Na+ Na+ Na+ Ca2+ Na+ Na+ Na+ Na+ Na+ Ca2+

d

d

Low Salinity





d


- - - - - - - - - - - - - - - - - - - - - - - - - d


- - - - - - - - - - - - - - - - - - - - - - - - - d


d


High Salinity

Figure 3.3: Schematic of Electric Double Layer in High and Low Salinity Environments

Lee, 2010 (BP) report the results of “small angle scattering” experiments to measure the thickness of the diffuse water layer around silica particles dispersed in oil with the electro-chemical properties of the surface of the particles adjusted to be claylike. The salinity and



valency (that together form the ionic strength) of the water film was varied between experiments. The results indicate that the lower the salinity the thicker the layer, with monovalent cations giving less variation in thickness than divalent ions. From this the authors conclude that the exchange of divalent ions for monovalent ions at low concentrations can significantly enhance the thickness of the water layer and this provides “some support” for BP’s proposed explanation that expansion of the double layer triggers the Multicomponent Ion Exchange (MIE) mechanism (Lager, 2007). However, there is no direct demonstration of the mechanism, just of double layer expansion.

Ligthelm, 2009 (Shell) report that the apparent main mechanism for how low salinity water flooding works is the expansion of the double layer, and the subsequent desorption of oil from the clay surfaces.

Double layer expansion is also mentioned by University of Stavanger researchers (Austad, 2010) but their suggested mechanism on how low salinity water flooding is working is not dependent on this expansion.

All this is discussed further in Section 3.5.

3.2.3 Ion Exchange

Clays have the capability of exchanging ions with the surrounding fluid. The equilibrium between ions in the water phase and ions adsorbed to the clay surface (Figure 3.4) depends on the concentration of ions in the water phase and the tendency of a particular ion to adsorb on the surface. The exchange equilibrium is also affected by temperature, pressure and pH.

The tendency for an ion to replace another is in this order:

Na+ < Mg2+ < Ca2+

This means that Ca2+ ions will replace both Mg2+ ions and (two) Na+ ions and Mg2+ will replace (two) Na+ ions. Note, however, that high concentrations of Na+ can reverse the process (as happens when NaCl is added to the ion exchanger in a dishwasher).

2+ 2++ Low salinity enhances this tendency Mg Ca< < Na

Ca2+ Na+ Na+ Na+ Ca2+ Na+ Na+ Na+ Na+ Na+ Ca2+

Ca2+

- - - - - - - - - - - - - - - - - - - - - - - - -

Figure 3.4: Ion Exchange

The cation exchange capacity (CEC) of various clays is given in Table 3.2 in meq/100g (milli-equivalents per 100 gram of material). A permanently charged clay like montmorillonite has a much bigger ion exchange capacity than kaolinite, with illite, that has both permanent and pH induced charge, somewhere in-between. However, the surface areas of these clays also differ and so the surface charge density may not follow the same trend.



3.3 In-Situ Osmosis

In-situ osmosis would seem to be an intuitive explanation for how low salinity water flooding works, because this mechanism fits well with the ingredients of clays being present, high salinity connate water and low salinity injection water. If clay particles form tiny membranes in pore throats the pressure would rise on the high salinity side, possibly forcing additional oil out of the pore.

This mechanism, therefore, should work regardless of the type of oil present. However, core experiments using mineral oil (that is oil without polar components) show no enhanced recovery with low salinity water flooding (Rivet, 2009; Buckley, 2009) so this explanation has now been dropped. According to Buckley, 2009 low salinity water flooding also works in reservoirs with low salinity connate brine which again weakens the osmosis theory.

3.4 IFT Reduction

The idea that low salinity water flooding works by a alkaline/surfactant mechanism came about because many low salinity core flooding experiments showed a rise in pH. Thus the released oil components could undergo saponification and react like surfactants (McGuire, 2005). It is also emphasised in McGuire, 2005 that predicting pH values for the field using geochemical models should take account of many factors including carbon dioxide partial pressures.

This mechanism has been rejected because low salinity water flooding has been seen to work for oils with a low acid number and because a rise in pH is not seen in all experiments (Rivet, 2009). In any case hydrocarbon reservoirs are generally at below-neutral pH conditions and there is considerable buffering provided by dissolved CO2 etc. If high pH is required for low salinity water flooding to work (say up to the range 9-10) then adding alkali, at least as a spearhead treatment, may be necessary in order to achieve these pH values around the injected water flood front. Useful combination with the alkali-based chemical EOR methods may be achievable as these processes also generally require low salinity water.

The oil-water surface active material that is loosened from the clay surfaces during low salinity water injection is regarded as the same that creates the wettability changes (see Section 3.5). Thus this explanation, and the double layer expansion, can be seen as effects that further enhance the recovery of oil, and not as competing theories to any wettability alteration mechanisms.

3.5 Wettability Alterations

There is considerable room for uncertainty about the role of wettability with conflicting conclusions about the choice between water wet or intermediate wetting improving oil recovery.

Changing the reservoir wettability from oil wet to water wet generally will improve the recovery of a water flood (Anderson, 1987). An explanation of this looking at pore size distribution, contact angles, etc., can be found inter alia in Sorbie, 2010 but no theories on the mechanisms behind this wettability change are presented.

Sharma, 2000 carried out centrifuge experiments, investigating the influence of brine salinity and wettability on oil recovery using connate brine of varying salinity. They found that the



recovery was higher with low salinity connate water than high salinity connate water, but that the salinity of the injected brine was of less importance. One of the important conclusions from their work is that it is not sufficient to look at the original wettability of the rock but rather to be able to track changes in the wettability during flooding cycles. They attributed the higher recovery to a movement from water wet towards more mixed-wet conditions. That might not be so contrary to the prevailing theory that low salinity water injection changes the wettability towards more water wet as the low salinity water was present in the cores initially and then displaced by high salinity water in the experiments.

So far all the low salinity experiments that have been carried out demonstrate that wettability and wettability changes are products of complex rock, brine and oil interactions and that wettability changes with temperature and saturation history. Reported saturation histories should include the salinity of the water phase and maybe other data related to water chemistry as well.

It is well established that the presence of clays influences the wetting properties of a formation. Also the oil composition, with polar groups in the oil and adsorbed onto the clays plays an important role in determining wettability.

When it comes to explaining the cause of the wettability change, two theories have been presented so far: the “MIE theory” favoured by BP and the “pH induced wettability change” espoused by Stavanger University. The differences in the explanations seem rather subtle in practical engineering terms, but they nevertheless have some implications on, for instance, the types of clays that need to be present and the composition of the low salinity water required for the different clay types as well the oil properties. Also, as discussed below, realistic setting of the CO2 buffered pH values pertaining to reservoir conditions has often not been achieved in the laboratory.

Normally clay is not regarded as beneficial to production of oil from a reservoir. Accumulations of clay particles reduce the permeability, swell and block the flow and are not desirable in low salinity water flooding either. Clay particles distributed in the sandstone pore structure, however, are believed to play an important role in the suggested wettability alteration mechanism explanations. This is so because the surface properties of the sand minerals are less influenced by changes in the ionic strength of the water.

3.5.1 Multicomponent Ion Exchange (MIE) Mechanism

Lager, 2006 presents the BP view that the mechanism behind the incremental recovery from low salinity water flooding is that free multi-charged cations replace the double layer cations that form complexes with organic functional groups at the clay surfaces. This results both in more water wet conditions and the mobilisation of oil components. The reason this mechanism works for low salinity and not for high salinity is that low salinity brine expands the electronic double layer of the clays (Lee, 2010). The view is also held by Shell (Ligthelm, 2009).

The concentrations of both the Ca2+ and Mg2+ ions in the low salinity water play an important role. However, it is not clear from the various references that discuss the MIE mechanism what the concentrations need to be to achieve incremental oil recovery. According to BP’s patent application (Lager, 2006-8), the concentrations of both these divalent ions need to be lower than the connate water concentrations, although not zero, but these constraints have been violated in many of the low salinity water floods and have still resulted in incremental



recovery. The effect of pH has to be included as ion exchange by H+ ions is important in addition to the effect of other cations, principally Na+, K+, Ca2+ and Mg2+.

For the MIE mechanism to work, clays, preferably kaolinite, have to be present. Clays that swell with fresh water and clays with a positive zeta potential, like chlorite, are detrimental to the improvement of oil recovery. In addition, connate water containing some concentration of Ca2+ ions has to be present for the method to work, as well as crude containing polar components (Lager, 2006-8).

3.5.2 pH Induced Desorption of Organic Material

Austad, 2008 and co-workers at the University of Stavanger suggested a “salt-in” effect to explain the additional recovery. “Salt-in” basically means that polar oil components are more soluble in water when the ionic strength of the water is low (i.e. low salinity water). This initial idea has now been elaborated and has changed towards a wettability alteration mechanism that, like MIE and the loosening of clay particles, results in a more water wet rock when injecting a low salinity fluid (Austad, 2010). In this mechanism the pH in the vicinity of the clay surfaces increases locally because the Ca2+ ions adsorbed on to the clay are substituted by H+. Adsorption of both base and acid oil components are very pH sensitive and the local increase in pH value leads to desorption of organic material from the clay surfaces and thus to enhanced water wettability.

This mechanism requires the presence of clays with a high cation exchange capacity, so the ranking of favourable clays follows their cation exchange capacity (CEC) ranking; montmorillonite better than illite/mica better than kaolinite. As a consequence of this theory, reservoirs that contain kaolinite or chlorite have to have a certain concentration of Ca2+ ions in the reservoir brine for low salinity water flooding to work, whereas there are no requirements relating to the softness if the rock contains montmorillonite or illite/mica. The crude has to contain polar components.

Oilfield waters generally have pH <7 due to the effect of dissolved acid gases (mainly CO2) and oil-based (volatile fatty and naphthenic) acids. Injected water will come into contact with hydrocarbons and become carbonated and adopt a more acidic nature than the surface water before injection. The in situ pH values applying to the reservoir and downhole conditions will be lower than those measured within surface samples due to loss of dissolved CO2, by perhaps 0.5-1.0 units in many cases.

Generally, it appears that the effect of dissolved CO2 has not been given due emphasis in core flooding methodology and in the theoretical discussion of pH effects on clays or organic polar species. Given that pH plays an important part in any desorption of organic components or on clay-based mechanisms then the simulation of reservoir condition pH becomes all the more important.

3.6 Discussion of Recovery Mechanisms

Most, if not all the above mechanisms are feasible ways in which oil recovery may be improved. It could be that a combination of effects influences laboratory core tests and field trials.



Figure 3.4: Schematic of Capillary Pressure at Curved Oil/Water Interface

Figure 3.4 illustrates capillary pressure at a curved oil/water interface. This pressure is responsible for retention of oil blobs and longer oil “ganglia” as illustrated in Figure 3.5. These visualisations reflect the effect of wetting (contact angle θ), interfacial tension (γ) and pressure gradients dp/dx). It is easy to appreciate that any change of contact angle toward 90 degrees (Cos θ=0, neutral wetting), lowering of interfacial tension or increase in applied pressure gradient would tend to enhance oil mobilisation and reduce trapping of oil droplets.

Figure 3.5: Schematic of Trapped Oil Ganglion

The length scales (influencing “l” of trapped connected oil) of pores, core samples and reservoir heterogeneities have important influences on oil trapping. Core tests are expected to show microscopic residual oil effects, assumed to be effectively “linear” flow processes and are often assumed to be free of capillary end effects. Unfortunately, capillary end effects are expected to be more sensitive to changes in wettability, interfacial tension and imposed pressure gradients than the microscopic residual oil which is the focus of interest in the tests. Evaluation of, or minimisation of, artefacts due to end effects should be seriously addressed in core test design, as well as the minimisation of random measurement errors. Intra-core heterogeneities can cause trapping of high oil-saturation patches and would impart a sensitivity to mobility ratio (and the stability of flood fronts). Interfacial and pressure effects therefore combine to determine oil recovery, and are influenced by the physical phenomena discussed above.

Hence, there are several perceived mechanistic advantages in low salinity water injection, while the quantification of the oil recovery benefit requires more precise assessment. Screening on purely technical grounds may not be the only useful approach, but logistical and economic factors should be considered up-front. There are significant advantages in the use



of low salinity water for polymer, surfactant and alkaline EOR processes and so combination of these methods with low salinity water flooding should be emphasised. Considering application economics, synergy with (sulphate reduction and desalination) water treatment technologies applied for other reasons, such as for scale control and reservoir souring prevention should be considered in the screening of candidate fields.



4 Chemical and Environmental Aspects

4.1 Offshore Production of Low Salinity Water

For conventional water flooding water is normally sourced from the sea. The water is filtered and deaerated, and biocide is added to reduce reservoir souring. In some cases the water is desulphanated to prevent the formation of sulphate scale as a result of incompatibilities between the injection and formation waters. In some cases more compatible water is sourced from nearby aquifers.

It may be that sources of water with a composition suitable for low salinity water flooding could be found in the aquifer formations immediately around offshore installations. Alternatively low salinity water for offshore applications could be produced by desalinating seawater. This is often done on a smaller scale offshore for potable water and for to mix water based mud. (where fresh water is required to swell the clays).

Seawater desalination methods can be either thermal or membrane based. Ayirala, 2010 has reviewed all the methods and discounted thermal methods principally on the physical size and weight of the plant involved, and the fact that the processes require large amounts of steam which is not easily available offshore. On the other hand, membrane-based reverse osmosis methods are attractive for offshore use because of suitable space, weight and energy requirements. However, a drawback is that reverse osmosis produces almost fresh water which would swell clays. Spiking back some of the reverse osmosis reject stream or mixing the fresh water with seawater adds back sulphate which is undesirable from a reservoir souring point of view. So Shell (Ayirala, 2010) are proposing an new desalination scheme which they have trademarked under the name “Designer Water” (Figure 4.1) which involves back to back nanofiltration and reverse osmosis stages; with the former reducing the hardness of the water including removal of SO4

2- and the latter reducing the salinity. The output is water with TDS <500 ppm which is lower than required (typically 1000-5000 ppm) so small quantities of the nanofiltered water or the reject streams at each stage are blended back to produce “Designer Water” of the required specification (Blending 1, 2 and 3 in Figure 4.1). Adding back divalent ions (but avoiding SO4

2-) is important in preventing clay swelling and flocculation.

Figure 4.1: Flow Schematic of Shell’s Designer Water Process



Such process plant could be incorporated on an offshore platform or even on a ship or floating facility (which would allow reuse). Shell see economic production of low salinity water offshore as the key to opening up the use of other water based EOR processes such as polymer flooding, alkaline/surfactant/polymer flooding and linked polymer systems (LPS) where the use of low salinity mixing water enables the use of smaller quantities and cheaper chemicals (as discussed in Section 3.6).

4.2 Costs

There are obviously expenditures associated with providing a source of low salinity water whether by building and operating a combined nanoflitration/reverse osmosis plant or exploring for and producing from an appropriate aquifer. The cost effectiveness will obviously depend on the amount and timing of the incremental recovery. Additional benefits would be a reduction in scaling and souring risk with a consequent reduction in the cost of chemicals.

4.3 Environmental Issues

If low salinity water is sourced from a combined nanoflitration/reverse osmosis plant the high hardness and salinity reject streams will require to be disposed of overboard. Also any solids, sludges, or filter media that are by-products of the process.

This should not be an insuperable problem and would be dealt with at the environmental impact assessment stage.



5 Screening Criteria Despite the different explanations of how low salinity recovery works and the many parameters that apparently play a role which leaves a somewhat confusing picture, there seems to be agreement on some common features:

• Clays have to be present and distributed in the formation.

• Formation water and/or seawater (high salinity) from prior flooding has to be present.

• The low salinity injection water has to have a salinity below some limit (TDS <~0.5% or 5000 ppm).

• The oil has to contain polar components.

• The reservoir has to be oil wet or intermediate wet (or mixed wet).

In addition to these five points according to the MIE explanation the concentration of Ca2+ in the injected low salinity water needs be lower than the Ca2+ concentration in the connate water, although this requirement is not as widely accepted as the points above.

None of these requirements is without exception but can be applied as rough screening criteria to identify fields that might benefit from the method. However, because of the complex and often contradicting oil-brine-rock interactions suggested to explain how the process works, there is no theoretical predictive tool to determine the performance in individual reservoirs. Also, the above requirements are actually met by a great number of reservoirs and it is not easy to discount particular fields from consideration. At a high level, the wettability criterion could be used to exclude cases but even here it appears that there are exceptions to the rule. Preferably, the process has to be laboratory tested at realistic reservoir conditions (including temperature), using the valid core, reservoir oil and brine at the appropriate composition, pH etc for each candidate field. The required composition of the low salinity water has to be determined by trial and error, based on experience so far.

5.1 Clay

With the exception of the Tensleep formation (Buckley, 2009) investigations so far indicate that clays have to be present and distributed in the formation for low salinity additional recovery to work.

BP has found that low salinity works extremely well in the Endicott field (Seccombe, 2010), where the dominant clay is kaolinite. This is somewhat surprising as kaolinite, unlike many of the other reservoir clays, is a 1:1 clay with a limited cation exchange capacity (Section 3.2.1). However as this clay has a low specific surface area the effect of CEC on surface electrical effects is so much greater.

Clays that swell with fresh water and clays with a positive zeta potential are detrimental to the recovery according to the MIE explanation. The supposedly detrimental effect of chlorite is perhaps seen in Zhang, 2006, where Berea 60 core cannot be made to respond positively to low salinity water injection. Berea 60 has the same kaolinite content as other Berea cores but more chlorite.



The pH induced cation exchange mechanism for low salinity water flood recovery requires the presence of clays with a high cation exchange capacity, so the ranking of favorable clays follow their cation exchange capacity ranking: montmorillonite > illite/mica > kaolinite (Austad, 2010). According to this theory chlorite is not a showstopper. The swelling properties of montmorillonite are probably avoided if the injected water is not totally without ions.

Screening criterion: Distributed clays have to be present in the formation.

5.2 Ion Composition of the Injected Water

To date, none of the theories can indicate how low the concentration of salt has to be in order for low salinity water flooding to work, but all experiments so far seem to show that the salinity has to be below some field specific threshold (around 5000 ppm), but not zero in order to avoid clay swelling.

According to BP the multiple cation and divalent cation concentration in the injected water has to be lower than in the formation water for the method to work (Lager, 2006). The MIE theory requires Ca2+ ions in the injected water, implying that low salinity water injection does not work for pure NaCl solutions, or other brines not containing Ca2+. However, Tang, 1999 show that incremental recovery can be obtained from low salinity water flooding regardless of the valence of the cations injected.

From the pH theory the presence of Ca2+ and Mg2+ is important when the clay is kaolinite or chlorite but does not matter for montmorillonite or illite/mica.

Screening criteria: none. Trial and error core flood experiments have to be carried out with the right formation, oil and reservoir brine etc. at reservoir temperature to see if an effective salinity and water composition can be found. Salinities of the order 5000 ppm should be tested as a first estimate. Following favourable core test results, field tests like log-inject-log and single well reactive chemical tracer tests (SWCTTs) are recommended before inter-well field trials are contemplated.

5.3 Oil Composition

The oil composition influences the outcome of low salinity water flooding. Polar groups have to be present in the oil for the method to work. The more of these components that are present, the more the oil is thought to wet the formation, so there is probably a connection between this and the wettability criteria.

Screening criterion: Oil must contain a “fair amount” of polar components, i.e. relatively high acid or base number. Crude oils in general contain such components as volatile fatty and naphthenic acids which would be active in the desired manner; however, it may be difficult to exclude any particular crude oil from consideration.

5.4 Wettability

Wettability and wettability changes are products of complex rock, brine and oil interactions, temperature and saturation history. Thus applying the term wettability reflects on the importance of all the parameters, oil composition, clay content and type, water compositions and saturation history and perhaps these should not be put into one single simplified parameter.



The mechanisms causing low salinity improved recovery are probably dependent on all the parameters that determine the wettability, so it is probably not sufficient to find a formation oil wet or mixed-wet or intermediate wet to be certain that the reservoir is susceptible to low salinity water flooding. The interaction of parameters resulting in the wettability state might turn out to be unfavourable to low salinity water flooding.

If low salinity water flooding, by some mechanism, changes the wettability from the oil wet end of the spectrum to be more mixed/intermediate to water wet, the process will result in incremental oil recovery. To date, it would appear that few have tested directly whether low salinity moves the wettability towards more water wet, except maybe Sharma, 2000 where the salinity of the connate water was varied.

Nevertheless, the following screening criterion is suggested:

Screening criterion: Only reservoirs that are not strongly water wet and are towards the oil wet end of the wettability spectrum (i.e. intermediate, mixed or oil wet) should be considered.

5.5 Ranking of Fields for Low Salinity EOR Potential

As noted above it is not possible to screen for whether low salinity water flooding is appropriate in a particular field without doing reservoir condition core floods. However, it will be necessary to high-grade or rank fields on some basis in order to determine which ones to screen first.



Rock/Fluid Properties

Wettability (oil wet, intermediate wet, Amott Index?)

Oil/water IFT lowering (>50%)?

High salinity formation water (>5%)

High dispersed clay (kaolinite?)

High residual oil saturation (from core floods?) (>30%)

Reservoir/Facilities

Freshwater source (<= 5000 mg/l salts?)

Desalination feedstock water source (< 36,000 mg/l salts?)

Desalination plant practicable (space, weight etc)

High Ba, Sr, Ca in formation water (additional scale control benefits?)

Maturity of waterflood (relatively immature?)

Testing practicable (SWCTTs, confined pilot area pilot?)

Core material available (preserved?)

Potential Benefit

Remaining STOIIP (large?)

Potential for other water based EOR techniques (A/S/P, LPS, Bright Water?)

Table 5.1: Possible Criteria to Rank Fields for Low Salinity Water Flooding Potential

Table 5.1 is a suggested list of criteria to use for this purpose. We suggest that a scoring system be devised to go with these criteria and all reservoirs/flow units are screened to draw up a list of the most attractive prospects. These are then the initial candidates for the systematic laboratory screening programme.

We recommend that such a screening programme should be undertaken systematically and consistently by independent laboratories used to performing reservoir condition core floods and able to understand and quantify the uncertainties in the measurements. Our preliminary estimate is that a basic cost for the required experiments is in the range £10-20k per reservoir flow unit.

A particular issue is whether a mature water flooded field is ever too late in its development to benefit from low salinity water flooding. There may be some evidence relating to this from a simulation result from an earlier study by RML for DTI (Hughes, 2003). This was in fact a simulation of a 1D coreflood where it was postulated that an injected chemical agent could change the wettability of the water/oil/rock system from intermediate/oil wet to water wet. The relative permeabilities and corresponding fractional flow curves for these two states are shown in Figure 5.1. For both sets of curves the end point saturation to water flooding is 20% and the chemical had no effect on the phase viscosities.



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Figure 5.1: Intermediate/Oil Wet (left) and Water Wet (right) Relative Permeabilities used in Simulation

The results of the simulation are shown in Figure 5.2. The wettability changing agent was added to the injection water after 3.3 HCPV of water injection by which time the water cut was ~98% and the oil recovery about 63% of OIIP. The initial response to the wettability changing agent is seen after ~30% HCPV has been injected and the burst of incremental recovery which brings the total recovery to 80% OIIP (i.e. all the waterflood mobile oil) is all but complete after a single hydrocarbon pore volume of the wettability changing agent has been injected. During the period of incremental recovery the simulation predicts that the watercut falls to ~60%.

It is appreciated that this is a very optimistic and idealised calculation. But from this result, as a rule of thumb, it is suggested that only fields where there is sufficient time to inject one hydrocarbon pore volume of water in the targeted area should be considered; and it will be necessary to add to this an estimated lead time before low salinity water injection can begin. For practical purposes this probably rules out, or at least down grades, fields with an expected cessation of production date within the next 10 years.

Injection of wettability changing agent begins here (after 330% HCPV injected)

Injection of wettability changing agent begins here (after 330% HCPV injected)

Figure 5.2: Response to Wettability Change on Cumulative Recovery and Watercut



6 Conclusions and Recommendations

6.1 Conclusions

Significant programmes of work investigating low salinity water flooding have been undertaken by oil field operators and research institutes for almost 20 years. These have covered laboratory core floods, single well reactive chemical tracer tests (SWCTTs) and one well to well pilot of tertiary low salinity water flooding. In addition data on earlier low salinity secondary water floods has been analysed.

The main conclusions to be drawn from this research and development work are:

• Low salinity water flooding is an immature EOR technology but there does seem to be positive proof of field success. Uncertainty exists about the benefit with a suggested range of 0 to 12% OIIP.

• As yet there is no consensus of view on the mechanisms behind the process (i.e. what is causing the increase in recovery).

• As a consequence a priori prediction of which fields might be suitable and the potential incremental recovery in a given field is not possible, rather core floods and other laboratory studies are required followed by SWCTTs.

• A suitable source of low salinity water could be provided economically offshore from a combined nanofiltration and reverse osmosis processing plant or from a suitable shallow aquifer.

• Provision of a low salinity water supply in a field can act as a vanguard for other water based EOR processes such as polymer flooding, alkaline/surfactant/polymer flooding and linked polymer systems (LPS) with potential for even greater incremental recoveries. It can also overcome conventional problems such as souring and scaling.

• Although not yet proved, low salinity water flooding either alone or in conjunction with other water based EOR techniques has the potential to be a “game changer” in offshore reservoirs on a 3 to 8 year time frame.

6.2 Recommendations

It is recommended that:

• All fields where water flooding is ongoing or planned should be screened to determine the potential benefit of switching to low salinity water flooding. This should be undertaken systematically and consistently by independent laboratories using standard methodology. Such national screening programmes should be centrally organised but funded by operators. The opportunity should also be taken to extend this to systematic screening of the potential for other water based EOR techniques. A strategy is suggested to high grade the fields that should be the initial candidates for the screening.

• The current experimental methodologies around low salinity water flooding should be refined and standardised. Experiments need to be carried out at reservoir conditions



(including temperature, CO2 partial pressure and pH) using live crude, reservoir brine and native core with wettability conditions restored. Capillary end effects should be minimised and CT scanning or other techniques to record in situ residual oil saturation should be considered. Flow rates and pressure gradients need to be monitored and controlled during core testing and related to field inter-well gradients and rates. Uncertainties in core flood measurements need to be reliably assessed (random errors claimed to be below +/-1.5%, but systematic effects uncertain) in order to evaluate the significance of the improved oil recovery data. We estimate that at a basic level such a programme would cost between £10-20k per reservoir flow unit.

• DECC/NPD should initiate a study to investigate the costs of building and operating a combined nanofiltration/reverse osmosis plant on an offshore platform or on a reusable floating vessel.

• DECC/NPD should encourage operators to share more detailed information on their investigations and publish more data on oil composition, and injected and produced water compositions in SCAL experiments.

• DECC/NPD should ask operators to consider the economic benefits of low salinity water flooding ‘in the round’; i.e. it can also reduce souring and scale, yield cost savings on production chemicals and corrosion management, and reduce safety and environmental costs.



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