On Oil Recovery Mechanisms and Potential of DME-Brine Injection in

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Thermodynamics, Transport, and Fluid Mechanics

On Oil Recovery Mechanisms and Potential of DMEBrine Injection in the North Sea Chalk Oil Reservoirs Hoda Javanmard, Mojtaba Seyyedi, and Sidsel Marie Nielsen Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.8b04278 • Publication Date (Web): 29 Oct 2018 Downloaded from http://pubs.acs.org on November 4, 2018

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Industrial & Engineering Chemistry Research

On Oil Recovery Mechanisms and Potential of DME-Brine Injection in the North Sea Chalk Oil Reservoirs Hoda Javanmarda*1, Mojtaba Seyyedia2, Sidsel M. Nielsena 3 a)

Danish Hydrocarbon Research and Technology Centre, DTU, Lyngby, Denmark

[email protected]

Abstract North Sea tight chalk oil reservoirs are well-known for their sub-micron pore throat sizes and heterogeneous porosity pattern that includes fractures and micro fractures. The host rock of these reservoirs is extremely sensitive and can easily react with the injected fluid, which in turn adversely affects the permeability and thus injectivity. The combined effect of these parameters makes oil production in chalk reservoirs extremely difficult. A novel solvent-based enhanced oil recovery (EOR) method that can address these issues is investigated for the first time in the chalk reservoirs. We thouroughly investigate the oil recovery potential and dominant oil recovery mechansims by Dimethyl Ether (DME)-brine injection under conditions pertinent to the North Sea tight chalk oil reservoirs. A series of systematically designed high-pressure and high-temperature flooding experiments were carried out using reservoir core and crude oil. The experimental results revealed the strong oil recovery potential of tertiary DME-brine injection with two different DME content. Furthermore, both secondary and tertiary DME-brine injection scenarios significantly improved the oil recovery with the better performance in secondary scenario. The results

1

Geothermal Energy & Geofluids group, Institute of Geophysics, ETH Zurich, Switzerland

2

Chemical and Petroleum Engineering Department, University of Calgary, Canada

3 Novo Nordisk A/S, Smørmosevej 17-19, DK-2880 Bagsværd, Denmark

1 ACS Paragon Plus Environment

Industrial & Engineering Chemistry Research 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

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show that the dominant oil recovery mechanism is rapid and strong oil swelling caused by the preferential partitioning of DME into the oil phase. During DME-brine injection, no indication of rock mineral dissolution and adverse effects on rock permeability was observed. This is one of the advantages of this method over CO2, CO2-water alternating gas (WAG) and alkaline injections in which the EOR agent causes calcite dissolution, wormhole formation and scaling issues in fragile chalk reservoirs.

1. Introduction Hydrocarbon production from chalk reservoirs is a challenging task due to the low permeability of the matrix (typically 1 millidarcy 1), presence of fractures and the special mechanical behaviour of chalk when subjected to water 2 or chemical flooding 3. The average recovery factor in the North Sea oil fields even after seawater flooding is still very low; for example around 30% of the estimated original oil in place (OOIP) in the Danish North Sea 4. Therefore, it is of high importance to implement suitable enhanced oil recovery (EOR) scenarios in the existing fields. However, the aforementioned factors put a limitation on applying available EOR scenarios. For example CO2 injection is one of the most successful EOR methods worldwide, however, CO2-chalk interactions lead to wormhole formation and formation damage 5. Moreover, CO2 availability issue and the cost of such project offshore 6 hinder implementation of such project even further. Adverse effects of other techniques such as matrix acidizing on the mechanical stability of chalks 7,8 and other rock types 9 are also well documented in the literature. This study aims to investigate a novel solvent based EOR method that can match the performance of CO2 injection but does not pose its limitations in the chalk fields of the North Sea. Dimethyl Ether (DME) has recently attracted the attention of researchers in the oil and gas industry. Being mutually soluble in water and hydrocarbons with preferential partitioning into the oleic phase, makes DME a potential EOR agent 10. DME is the simplest ether with the chemical formula of CH3-O-CH3. It is a colourless gas in atmospheric condition but can be liquefied under modest pressure or cooling. This


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organic compound is non-toxic, non-corrosive and non-carcinogenic 11. Due to its remarkable properties, research on various potential applications of DME has recently gained momentum 12–16. For oil exploitation purposes, DME can be injected into oil reservoirs mixed with injected water/brine. When in contact with the hydrocarbons in the reservoir, DME transfers into the oil phase, creating a mobile phase and results in recovery improvement. Since DME preferentially partitions into the oil, most injected solvent can be recovered from the produced fluid. The remaining DME in the reservoir is also recoverable by chase waterflooding. As reported by Te Riele et al.

17

based on two full field DME-EOR

implementation design, up to %70 of the solvent can be recovered and recycled. Hence most of the solvent can be recycled and reinjected, making the process economically viable. Properties of pure DME are well documented in the literature 18–22, however, since the idea of using DME in hydrocarbon production is rather new, relevant data in the literature is limited. Chernetsky et al.23 and Ratnakar et al.24 measured density and viscosity of binary systems of DME, brine and oil as well as partition coefficient of DME between brine and oil. They also studied phase behaviour modelling of the three phase system in reservoir conditions and suggested equations of state or empirical correlations to estimate partitioning of DME between brine and oil 23–28. Chernetsky et al. 23 showcased the results of two tertiary corefloods performed on carbonate rocks, one in continuous and one in slug injection mode. Parsons et al. 29 presented results of a tertiary DME coreflood on sandstone using live crude oil. Chahardowli et al. 30,31

studied the effect of polymer addition to DME-brine solution in order to control the mobility of

displacing fluid for high viscosity oils through coreflooding experiments. Chahardowli et al.32 also studied the impact of DME on spontaneous imbibition of oil in carbonate and sandstone cores. Groot et al.

33

carried out reservoir scale simulations for the DME EOR technology and studied the sensitivity of the results to different design parameters. Te Riele et al.

34

investigated the importance of reservoir

management and designing suitable well patterns in the field implementation of this technology. They simulated two different scenarios to demonstrate how design parameters affect the overall performance 3 ACS Paragon Plus Environment


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of DME EOR. Alkindi et al. 35 designed a potential DME EOR pilot plant for an oil field in Oman. Sheng at al.36 studied suitability of DME as an additive for steam injection in recovery of heavy oil and bitumen. Ganjdanesh et al.37 examined the performance of DME in removing condensate in hydraulically fractures reservoirs. Most proposed EOR methods in the chalk fields enhance recovery by up to 10% 38–40 while the additional recovery by DME EOR method in the literature ranges from 10 to 35% for different rock types

23,29.

Considering the great potential this novel technique presents, the current study aims to investigate the DME EOR technique in greater depth and address the following uncertainties that are not discussed in the open literature: -

In all previous studies, the EOR agent was fully saturated with DME at the experimental condition. Since DME preferentially partitions in the oleic phase, the saturation of DME in the front of the EOR agent continuously reduces which may impact the ultimate oil recovery. Therefore, to gain a better understanding of the oil recovery potential of the proposed method at distances far from the injection well, conducting experiments under different saturations (i.e. DME content in the DME-brine solution) is essential.

-

Oil viscosity reduction is pointed out to be a contributing factor in improving oil recovery by DME EOR23,30. However, since the North Sea oil is very light with viscosity of less than 1cp, we believe viscosity reduction cannot lead to major recovery enhancement. Therefore, it is important to investigate if other mechanisms such as oil swelling are strong enough to lead to favourable results.

-

All available DME EOR coreflooding data are in tertiary mode. It is important to investigate how the secondary EOR scenario performs compared to tertiary for technology implementation purposes.


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-

As discussed above, chalk can easily be unfavourably affected by EOR agents. Possible mineral dissolution and precipitation can cause changes in permeability and porosity of the formation and affect rigidity of the rock. Such adverse impacts are well documented in the literature for different rock types

41,42.

Therefore, it is crucial to ensure that the proposed technique does not

considerably alter the permeability and porosity of the rock. -

The focus of all published literature on DME EOR was either to investigate the PVT behaviour of the DME/brine/oil system or the technical implementation of the technology. In the current study our main goal is to identify active mechanisms that lead to enhanced oil recovery.

This study aims to target the abovementioned void in the literature and investigate the true potential of DME as an EOR agent by means of carefully designed coreflooding experiments under real reservoir conditions. First materials and methods used are introduced where an oil field in the North Sea was chosen, chalk cores and reservoir crude oil were sourced from this field, and several coreflooding experiments were carried out under targeted reservoir conditions to investigate different scenarios. This is followed by the results of coreflooding experiments and an in-depth analysis of the results in terms of complex fluid-fluid and fluid-rock interactions to shed light on physical mechanisms that are active in improvement of ultimate oil recovery.

2. Materials and methods 2.1. Core Plugs Four tight chalk core samples from a North Sea oil reservoir were used in this study. To ensure homogeneity of flow path, all core plugs were imaged, in both lateral and longitudinal directions, using a fourth generation Siemens SOMATOM Plus medical grade CT scanner. The cores chosen for the study did not contain any fracture or high permeability layer (thief zone). The screening procedure was intended to maximise the chance of piston like displacement in the coreflood experiments. The obtained CT scan images for core 1 is shown in Figure 1. Cores were cleaned using toluene and methanol in a flow-through 5 ACS Paragon Plus Environment


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apparatus under high-pressure and high-temperature conditions. Each core was then assembled in the coreflood system maintained at the experimental temperature (60°C) and was evacuated for at least a couple of hours. When the pressure gauge showed stable vacuum in the system, the core was isolated from the vacuum pump and formation brine was injected to the core up to the experimental pressure (2755 psi). The amount of formation brine injected to the core was recorded as the pore volume of the core under experimental condition. This value was used to calculate the porosity of the core. The core was then subjected to different flow rates of formation brine. From the pressures recorded in the inlet and outlet of the core, permeability of the core to formation brine was calculated. All measured parameters are reported in Table 1.

Figure 1 - Images obtained from CT scanning of core 1. From left the first two in longitudinal and the last one in lateral direction.

Table 1 - Properties of chalk core plugs

Core plug

Diameter (cm)

Length (cm)

Porosity (%)

Permeability (mD)

Core 1

3.8

5.6

32

1.15

Core 2

3.8

9.5

26

0.53

Core 3

3.8

5.6

31

1.26

Core 4

3.8

5.2

25

0.36


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2.2. Fluids A light crude oil (µ = 0.6 cP) was sourced from the same oil field in the North Sea where the cores were drilled from. Synthetic formation brine and seawater were prepared in house based on the composition data received from the oil field in the Danish North Sea. The actual ionic composition of the synthesised formation brine and the seawater are presented in Table 2. Commercially available DME with 99.9 mole% purity was used in the experiments. To prepare the EOR agent, seawater and DME were thoroughly mixed at the experimental pressure and temperature (2755 psi and 60C). The saturation of DME-brine solution is affected by pressure, temperature, and brine salinity 23,24. By increasing the pressure and/or dropping the temperature and/or decreasing the brine salinity, the saturation of DME in the specific brine can be increased meaning that more DME may be dissolved in the brine. Therefore, it was critical to mix DME and seawater at the experimental condition to avoid under-saturation or DME pure phase in the EOR agent. Particular to the synthetic seawater and experimental conditions of this study, the fully-saturated EOR agent contains around 20 wt% (10 mole%) of DME in the solution. All the prepared DME-brine solutions were fully saturated with DME unless otherwise stated. Table 2 - Composition of synthetic formation brine and seawater Formation Brine (ppm)

Seawater (ppm)

27286

10744

K+

249

400

Mg++

592

1094

Ca++

1466

410

Sr++

140

20

Ba++

1

-

46300

19350

-

65

Na+

ClHCO3-



SO4-

290

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2000

2.3. Experimental Setup A schematic of the coreflooding system used in this study is shown in Figure 2. The in-house designed and built high-pressure high-temperature coreflooding system consists of two pumps, four injection cylinders, biaxial core holder, a back pressure regulator (BPR) and effluent collection system. The effluent went through a gas separator where the liquid was collected in graduated test tubes and the separated gas went through a wet gas flowmeter. The core, all the fluids being injected into the core, and the BPR are kept inside an oven. One pump supplies constant pressure to the core holder sleeve, the pressure of which is kept 725 psi above the core inlet pressure at all times. The second pump provides constant flow rate of the fluid injected to the core. The oven maintains the system in reservoir temperature and the BPR ensures the reservoir pressure. Accurate pressure transducers are installed in the inlet and outlet of the core holder. The pressures and injection rates are continuously logged throughout the flooding procedure.


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Figure 2- Schematic of the coreflood system. The red line represents the temperature controlled part of the experimental setup. The black lines represent the flow lines. The grey dashed lines are the data lines.

2.4. Experimental procedure For each experiment, the core was wrapped in Teflon tape, heat shrinkable sleeve and hydrogenated nitrile sleeves. All materials used are DME resistant to ensure no DME loss due to DME adsorption into and through the wrapping material. The porosity of the core and the permeability to formation brine were then measured at the experimental conditions. Initial water saturation was established by injecting the crude oil to the core saturated with formation brine until no more brine was produced. The cores were subjected to 3-weeks long aging process at 80°C to make sure the wettability of the core plug resembles the state in reservoir. To examine the oil recovery potential of DME-brine injection, three coreflood experiments were carried out. Please note if the EOR agent was injected to the core following seawater flooding the experiment is referred to as tertiary mode and if not, the experiment is referred to as secondary mode in this manuscript. In the first and second experiments, conventional seawater injection was followed by tertiary



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half- and fully-saturated DME-brine injection, respectively. In the third experiment fully-saturated DMEbrine solution was used in a secondary recovery mode. The fourth experiment was a single-phase experiment in which the EOR agent was kept in dynamic contact with the core for an extended period to investigate fluid-rock interactions. For all experiments, the oil recovery and the differential pressure across the core were carefully recorded. A summary of these experiments is presented in Table 3. All experiments were carried out under current pressure and temperature of the targeted oil reservoir, i.e. 2755 psi and 60°C. Table 3 - Summary of experiments

Experiment Number

Core plug used

Flooding Mode

EOR Agent Saturation

Purpose of Flooding

1

Core 1

Tertiary

Half-saturated

Impact of Saturation

2

Core 2

Tertiary

Fully-saturated

Impact of Saturation

3

Core 3

Secondary

Fully-saturated

Injection Scenario

4

Core 4

Fully-saturated

Fluid-rock interaction

Secondary (single phase)

3. Results and Discussion To investigate the oil recovery potential and dominant oil recovery mechanism by DME-brine injection in the North Sea chalk oil reservoirs, a series of carefully designed coreflood experiments under reservoir conditions were conducted using reservoir cores and crude oil. First, the results of the experiments in terms of recovery improvement will be presented. Next, the dominant mechanisms of oil recovery will be discussed.

3.1. Results 3.1.1. Impact of DME-Brine Saturation To investigate the impact of DME-brine saturation on the oil recovery performance, two coreflood experiments were conducted. In the first and second experiment following the conventional 10 ACS Paragon Plus Environment

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waterflooding, the core was flooded with half- and fully-saturated DME-brine mixture, respectively. The obtained oil recoveries presented in Figure 3 show that the performance of secondary waterflooding in both experiments was similar. This observation confirms the repeatability of our experiments. In both experiments, the water breakthrough was observed soon after injection followed by a long tail of oil production. Conventional waterflooding in both tests resulted in oil recovery of about 55% of OOIP. Both half- and fully-saturated DME-brine solutions showed a significant potential to produce the oil that was bypassed by waterflooding, thus improved the ultimate oil recovery. However, the tertiary DME flooding performance was much stronger when fully-saturated DME-brine solution was used. Tertiary half-saturated DME-brine solution led to 10.6% OOIP additional oil recovery, while tertiary fully-saturated DME-brine solution improved the oil recovery by additional 31.4% OOIP. As shown in Figure 3, in spite of the significant difference in ultimate oil recovery, the extra oil recovery in both cases started after almost one pore volume injection (PVI) of EOR agent. The oil production delay is a common observation in most tertiary EOR scenarios (for example see 43–45). Although unavoidable, the solvent retention time can be optimised by using different well patterns 17. It is clear that the rate of oil production in both cases is very high at least in the early stages of the production. However, the injection of 3 PV of half-saturated DME-brine solution resulted in a recovery plateau while in fully-saturated DME-brine injection, even after 6 PVI, oil recovery was still being observed. This indicated that the remained oil was not fully saturated with DME, thus more DME from the injected EOR agent was still being transferred to the oil. It should be noted that, the factor that controls the extent of DME mass transfer from DME-brine solution into the oil is the partition coefficient of the particular fluid system. The partition coefficient is the ratio of DME concentration in oil to DME concentration in brine when the phases (brine and oil) are in equilibrium across the interface. This value is case specific and is affected by a series of parameters such as pressure and temperature. In the same experimental condition, assuming the partition coefficients of both systems are the same, one can expect the ultimate 11 ACS Paragon Plus Environment


possible concentration of DME in the oil phase when half-saturated EOR fluid was used, to be half of that when fully-saturated EOR agent was injected. It is clear from the recovery curves in Figure 3 that the oil phase reached the highest possible DME concentration after 3 PVI of half-saturated EOR agent therefore no more oil production was observed. 100 90

31.4 % OOIP

80 70

RF (%OOIP)

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

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10.6%

60 50 40 WF-Exp 1 Half-saturated DME- Exp 1 WF-Exp 2 Fully-Saturated DME-Exp 2

30 20 10 0 0

2

4

6

8

PVI

10

12

14

16

Figure 3: Observed oil recovery factors (RF) in experiments 1 and 2. Tertiary fully-saturated DME-brine injection clearly outperforms tertiary half-saturated DME-brine injection. WF is secondary mode waterflooding.

3.1.2. Injection Strategy The oil recovery performance of fully-saturated DME-brine solution under different injection scenarios was investigated during experiments 2 and 3. In experiment 2, waterflooding was followed by the tertiary DME-brine injection, while in experiment 3 the core was flooded by the DME-brine solution in secondary mode. Oil recovery curves during these two experiments are shown in Figure 4. Both secondary and tertiary DME-brine injection showed significant potential in improving the oil recovery from tight chalk cores. However, the obtained oil recovery by secondary DME-brine injection was higher than tertiary DME-brine injection. This behaviour can be attributed to the fact that in the 12 ACS Paragon Plus Environment

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secondary scenario the residual oil saturation is higher than tertiary scenario. Furthermore, the trapped oil in a tertiary scenario is in the form of disconnected oil ganglia which will be more challenging to produce. Compared to the conventional waterflooding, secondary DME-brine injection led to 37.0% OOIP extra oil recovery while in the tertiary mode the recovery improvement is 31.4% OOIP. It should be noted that even after 6 PVI, the oil recovery in secondary DME-brine injection did not reach a plateau and oil production was still observed. These observations indicated that the equilibrium between the DME-brine solution and trapped oil phase was not yet achieved, thus more DME from the injected EOR agent was still being transferred to the oil phase. The same behaviour was observed in the tertiary DME-brine injection which means as long as DME is being transferred to the residual oil, production will continue. The oil recovery graphs in both secondary and tertiary scenarios show that the recovery factor slows down with PVI. This behaviour is due to the decline in the amount of oil in place, as well as reduction in the mass transfer rate between DME-brine solution and the DME-oil phase.



100 90 80

37.0% OOIP

70

RF (%OOIP)

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

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31.4 %OOIP

60 50 40 30 WF-Exp 2

20

Fully-saturated DME-Exp 2 Fully-saturated DME-Exp 3

10 0 0

2

4

6

PVI

8

10

12

14

Figure 4: Oil recovery factor during conventional waterflooding (WF), secondary and tertiary DME-brine injection. Both secondary and tertiary DME-brine injection presented a significant potential to improve the oil recovery in tight chalk oil reservoirs, with the better performance in the secondary mode

Figure 5 presents water cuts during both conventional waterflooding and secondary DME-brine injection. Water breakthrough in both cases was observed at the same PVI. However, in secondary DME-brine injection, the amount of produced water after the breakthrough is much less than that of conventional waterflooding. This observation reaffirms the better oil recovery performance by DME-brine injection compared to conventional waterflooding observed from recovery curves (Figure 4). In the conventional waterflooding, the water cut reaches the value of around 100% after only 2 PVI, whereas in secondary DME-brine injection, the water cut value was still less than 96% after 6 PVI. The lower water cut presented by DME-brine injection is an indication of better water conformance control by DME-brine than conventional seawater.


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100 90 80 70

Water cut

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


60

WF-Exp 1 DME-brine- Exp 3

50 40 30 20

Breakthrough

10 0 0

1

2

3

PVI

4

5

6

7

Figure 5: Comparison of the water cut during conventional waterflooding (WF-Exp 1) with that of secondary DME-brine injection (DME-brine- Exp 3). Breakthrough times for experiment 1 and 3 are 0.30 and 0.38 PVI, respectively.

3.1.3. DME back recovery The coreflood system is equipped with a wet gas flow meter (Figure 2) which records the volumetric flow of the gas stream produced. Results of the mass balance of DME in the system indicates more than half of the injected DME can be recovered from the produced fluid during the DME-brine injection phase. All experiments were completed by a chase water flooding phase to quantify the ultimate amount of DME recoverable from the core. Table 4 reports the percentage of injected DME recovered for each experiment. Due to malfunction of the flowmeter during the chase water flooding in experiment 1 DME recovery data were lost. Overall the results show that more than %70 of the injected solvent can be recovered. Table 4 - Efficiency of DME recovery from produced fluids and chase water flooding

Experiment number

DME recovery during DME-brine injection (%)

Ultimate DME recovery (%)

1

60.50

--

2

61.04

88.79

3

55.85

73.19



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1.1. Discussion As discussed in the previous section, both secondary and tertiary DME-brine injection presented a significant potential for enhancing oil recovery from tight chalk oil reservoirs. To gain insight into the dominant oil recovery mechanism by this novel EOR method, additional experiments were carefully designed and carried out. Supplementary data from the coreflooding experiments presented in the previous section were also analysed to examine the oil recovery mechanisms by DME-brine injection. The outcomes are discussed in mineral dissolution/precipitation and fluid-fluid mechanism sub-sections. 1.1.1. Mineral dissolution/precipitation In order to investigate whether DME-brine solutions react with chalk and cause any mineral dissolution or precipitation resulting in variations of the absolute permeability of the rock, a single-phase flow experiment was carefully designed and performed. Figure 6 presents the differential pressure across the core versus time during continuous DME-brine injection at different rates. The injection was continued for almost 70 hours. As shown in Figure 6, for each injection rate, the differential pressure across the core remained constant during the injection. This observation indicates that DME-brine solution did not react with the chalk and did not cause any mineral dissolution. Following the fairly long dynamic contact of the DME-brine solution with the reservoir core, the core was flushed with seawater. The permeability of the core using seawater was then measured again. No meaningful change in the permeability of the rock was observed. Therefore, it is safe to conclude that the core’s pore geometry and permeability remain intact during DME-brine injection in tight chalk North Sea oil reservoirs. This finding is of great importance both in understanding of the active EOR mechanisms and in technology implementation. Firstly, it confirms that the dominant mechanism causing the oil recovery enhancement lies in the fluid-fluid interaction. Secondly, it reveals that this EOR technology is suitable even for the


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fragile chalk reservoirs in which the rock can easily be dissolved in high or low pH solutions, and where mineral dissolution is a main concern. Mineral dissolution can cause formation damage around the wellbore and in severe cases wellbore failure. Therefore, great care must be taken for implementing EOR methods, such as carbonated water injection (CWI), CO2 injection, CO2-WAG (water alternating gas) and any other type of EOR scenarios that includes CO2, in fragile chalk reservoirs. In all these scenarios as CO2 will be dissolved in the formation or injected water, it will form in-situ carbonic acid that easily reacts with chalk, which leads to formation damage, wormhole formation and mineral dissolution and precipitation46– 51.

Compared to these EOR scenarios, DME-brine injection has the advantage of not causing any of these

issues while it shows a significant oil recovery potential. 30

Rate= 6 cc/hr

25

dP (psi)

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


20 15

Rate= 2 cc/hr

10 5

Rate= 0.2 cc/hr

0 0

10

20

30

40

50

60

70

Time (hr)

Figure 6: Differential pressure (dP) across the core during DME-brine injection, at different injection rates, versus time in the single-phase flow test. No indication of mineral dissolution and precipitation was observed.

1.2. Fluid – Fluid interaction 1.2.1. Oil swelling Figure 7 shows the oil recovery and differential pressure (dP) across the core during both tertiary mode half- and fully-saturated DME-brine injection corresponding to experiments 1 and 2, respectively. Clear 17 ACS Paragon Plus Environment


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from the graphs, regardless of the DME content in the DME-brine solution, as soon as the front of DMEbrine reaches the core inlet, a rapid increase in the differential pressure across the core is observed. This behaviour is similar to what is observed during CWI in live oil systems. Sohrabi et al.52,53 reported that when CW front touches the core inlet, a sudden increase in differential pressure takes place which is due to the strong oil swelling caused by CWI. DME is first contact miscible with the oil phase and partially soluble in water/brine 24. When the DMEbrine front reaches the reservoir fluids (oil and brine), DME partitions into the reservoir fluids. The partitioning leads to oil swelling which has been observed an effective mechanism in coalescence of isolated oil ganglions and local flow diversion

54.

As a result, the relative permeability of DME-brine

solution decreases causing the differential pressure across the core to increase. Comparison of differential pressure across the core during half- and fully-saturated DME brine solutions (Figures 7A and 7B) shows that the extent of increase in differential pressure is directly related to the DME content in the DME-brine solution. Higher DME content in the DME-brine solution leads to higher DME partitioning and thus stronger oil swelling, which in turn leads to the higher differential pressure across the core. As indicated in by the black dashed regions in Figures 7A and 7B, after DME-brine reached the core inlet, the differential pressure across the system started to increase until it reached a maximum value. Then, as oil started to produce and the DME-brine relative permeability increased, the differential pressure across the core started to decrease. However, contrary to the conventional waterflooding, the decrease in differential pressure did not continue for long. After less than half pore volume of DME-brine injection, although oil production was still being observed, the differential pressure reached a constant value, in half-saturated DME-brine injection, and it started to increase, in the fully-saturated DME-brine injection. As shown in Figure 8, during conventional waterflooding, after the water breakthrough, as oil is produced, the water relative permeability increases and thus the differential pressure across the core decreases until 18 ACS Paragon Plus Environment

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no more oil is being produced. Comparison of the observed differential pressure behaviours across the core between half- and fully-saturated DME-brine injections with conventional waterflooding confirms the strong oil swelling that takes place during DME-brine injection. Although oil was being produced during tertiary DME-brine injection, which naturally yields to an increase in the DME-brine relative permeability, the strong and rapid oil swelling led to the reduction in the brine relative permeability, therefore an increase in differential pressure across the core was observed. Comparison of the orange dashed regions in Figures 7A and 7B shows that the extent of the increase in differential pressure or oil swelling is related to the DME content in the DME-brine solution. The higher the DME content in DME-brine solution, the higher are the oil swelling, differential pressure, and the oil recovery.



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50

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10 0

0 0.00

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Figure 7: Oil recovery (RF) and differential pressure (dP) across the core versus pore volume of injection during tertiary A: half- and B: fully-saturated DME-brine injection (Experiment 1 and 2, respectively). A rapid increase in differential pressure is observed as soon as DME-brine solution touches the core inlet.


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140 WF-Exp 1

DME-brine- Exp 3

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dP (psi)

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80 60 40 20 0 0.0000

1.0000

2.0000

3.0000

4.0000

5.0000

6.0000

7.0000

PVI Figure 8: Differential pressure (dP) behaviour across the core during conventional waterflooding (WF) and secondary DME-brine injection.

Figure 8 compares the differential pressure across the core during secondary DME-brine injection and conventional waterflooding. In the latter, differential pressure across the core started to decrease following the water breakthrough. The drop in differential pressure continued for as long as oil production was observed. In secondary DME-brine injection, consistent with the conventional waterflooding, the differential pressure decreased following the water breakthrough. However, this only continued for a short period after which a continuous increase in differential pressure was recorded. The short period of drop in the differential pressure is due to the oil production and increase in DME-brine relative permeability. Nevertheless, the DME-brine relative permeability was negatively impacted by the strong oil swelling which outperformed the positive influence of oil production on improving the DME-brine relative permeability and led to an increase in differential pressure.



Page 22 of 32

To further investigate if the main reason for the increase in differential pressure across the core during DME-brine injection is oil swelling and not any other parameter, after each experiment, the core was flushed with seawater under exactly the same experimental condition. Figure 9 presents the differential pressure during the extended waterflooding in experiments 2 and 3. According to this figure, as soon as the seawater was injected into the core following the tertiary flooding, the differential pressure across the core started to decrease and a sharp drop in differential pressure was observed. It is noteworthy that no oil production was observed at this stage. Therefore, although during the extended waterflooding step no oil was produced, a sharp and continuous drop in differential pressure was observed. This behaviour can be attributed to DME depletion from residual oil inside the core, which in turn contributes to the decrease in the oil volume and saturation thus an increase in brine relative permeability and hence the reduction in differential pressure. The differential pressure reached a constant value after the residual oil inside the core was completely depleted from DME. This observation confirms that the increase in differential pressure across the core during DME-brine injection was mainly due to the rapid and strong oil swelling caused by DME-brine injection.


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450

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60 40 20 0 0.0000 1.0000 2.0000 3.0000 4.0000 5.0000 6.0000 7.0000 8.0000 9.0000 10.000011.000012.0000

PVI

Figure 9: Differential pressure (dP) across the core during experiments 2 (A) and 3 (B). WF is waterflooding.

1.2.2. Impact of DME on brine viscosity We estimated the viscosity of the brine and the DME-brine solution using Darcy law and the pressure data from experiment 4. It can be concluded from the data that the viscosity has increased from 0.7 to 0.86 cP (22.9%). Although the 22.9% increase in viscosity is considerable it cannot solely justify the consistently observed high differential pressure across the core during all DME-brine injections. In fact, the presented 23 ACS Paragon Plus Environment


Page 24 of 32

data shows that the viscosity increase is not the main contributor to the observed unusually high differential pressure after oil breakthrough in tertiary flooding. Therefore, the dominant oil recovery mechanism in DME-brine injection must be the strong and rapid oil swelling due to the preferential partitioning of DME from DME-brine solution into the oil. It should be noted that the transfer of DME from DME-brine into the oil can also lead to drop in oil viscosity which can favour the viscosity ratio and sweep efficiency of DME-brine. However, as the oil used in this study is very light at the experimental condition (0.60 cP), the impact of oil viscosity reduction on the obtained additional oil recovery is negligible. Oil viscosity reduction is much larger and therefore more effective for medium to heavy crude oils compared to light crude oils 55–57.

2. Conclusion To gain insight into the oil recovery potential and the dominant oil recovery mechanism by DME-brine injection in North Sea tight chalk oil reservoirs, a series of carefully designed flooding experiments were performed. The experiments were carried out under the most realistic reservoir conditions using reservoir crude oil and core plugs. The cores were aged to resemble the native wettability state of the corresponding oil reservoir. Based on the findings of this study, both half- and fully-saturated DME-brine injection have a significant potential for producing additional oil following conventional waterflooding, thus enhancing the oil recovery. Results of the DME recovery from the produced fluids indicates that there is a strong case for recycling this solvent. The presented experimental results are particularly valuable for the studies aiming to investigate field scale application of this method. The results revealed that the DME content of the EOR agent has a direct impact on the amount of oil recovered. The higher the DME content of DME-brine solution, the higher the oil recovery will be. Both secondary and tertiary DME-brine injection scenarios showed a significant potential for enhancing oil recovery. However, the performance of the secondary EOR scenario was better than the tertiary EOR scenario. Finally, the results clearly show that the dominant oil recovery mechanism by DME-brine injection in the North Sea tight chalk oil reservoirs is 24 ACS Paragon Plus Environment

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the substantial oil swelling due to the fast and strong partitioning of DME into the residual oil. The DMEbrine solution also does not cause any mineral dissolution in the studied reservoir rock; therefore, the pore geometry and core permeability will remain intact which is one of the advantages of this method compared to other EOR scenarios that include CO2.

Acknowledgments The authors would like to thank the Danish Hydrocarbon Research and Technology Centre for supporting this research under the Advanced Water Flooding program.

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Oil recovery factor during conventional waterflooding (WF), secondary and tertiary DME-brine injection. Both secondary and tertiary DME-brine injection presented a significant potential to improve the oil recovery in tight chalk oil reservoirs, with the better performance in the secondary mode 54x44mm (300 x 300 DPI)

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On Oil Recovery Mechanisms and Potential of DME-Brine Injection in

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