Mechanism Study of Disproportionate Permeability Reduction Using

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Mechanism Study of Disproportionate Permeability Reduction Using Nuclear Magnetic Resonance T2 Bin Liang, Hanqiao Jiang, Junjian Li, Fuzhen Chen, Wenpei Miao, Hanxu Yang, Yan Qiao, and Wenbin Chen Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b00420 • Publication Date (Web): 21 Mar 2018 Downloaded from http://pubs.acs.org on March 23, 2018

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Mechanism Study of Disproportionate Permeability Reduction Using Nuclear Magnetic Resonance T2 Bin Liang*a, Hanqiao Jianga, Junjian Li*a, Fuzhen Chenab, Wenpei Miaoc, Hanxu Yanga, Yan Qiaoa and Wenbin Chena *Corresponding author a State Key Laboratory of Petroleum Resources and Prospecting, and China University of Petroleum, Beijing. b School of Petroleum Engineering, China University of Petroleum, Qingdao. c Rice University, Department of Earth, Environmental and Planetary Sciences ABSTRACT Excessive water production is an enduring problem in the oil industry, which has always been an unbearable burden on the environment and a great damage to the ultimate oil recovery. Gel treatment has been routinely used for decreasing water production. Disproportionate permeability reduction (DPR) is a natural phenomenon for some polymer gels that can reduce the permeability to water more than to oil. The conformance improvement treatments with DPR can effectively reduce the water cut without substantially reducing the oil productivity in fractured reservoirs. At present, there are no widely accepted mechanisms of oil phase permeability development and DPR. In this paper, Nuclear Magnetic Resonance is applied to study the mechanisms of oil phase permeability development, DPR and permeability influence, by scanning different core samples treated with Cr(III)-acetate-HPAM gels. Results show that the permeability difference leads to a certain alteration in NMR T2 curves, but final conclusions for the mechanisms are consistent. For the mechanism of oil phase permeability development, initially, gel displacement in large pores accounts for the oil permeability development, after which the gel dehydration becomes the main mechanism. The mechanisms for DPR include the blocking of flow channels by gel rehydration and residual oil and the low permeability of gel relative to water. The results can be used to optimize the utility of polymer gels with a DPR property.

1 INTRODUCTION Global energy demand and consumption is forecasted to keep growing in the next 20 years [1], and fossil fuels supply more than 85% of the world’s energy with 32 bb/yr oil production. Most conventional resource was discovered between 1946 and 1980, and since then, annual production has exceeded annual discoveries [2]. The decline in the oil supply is supposed to be offset by the production from conventional fields through enhanced oil recovery (EOR), oil and gas supplies from unconventional reservoirs, such as shale gas, shale oil, tight gas, and other complex fractured reservoirs [3,4]. EOR is the oil recovery by the injection of materials not normally present in petroleum reservoirs, such as water-soluble polymer, steam,

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solvents, surfactants, and carbon dioxide [5-8], among which the cross-linked polymer is an important kind of EOR agents for the profile control and water shutoff. As the matrix of unconventional reservoirs is usually of low-permeability, these kinds of reservoirs generally call for both natural and hydraulic fracture networks to acquire an economic recovery of hydrocarbon [9]. However, in complex fractured reservoirs, when injector or producer is connected to faults or fractures, injected water can rapidly break through into the producers. For reservoirs with bottom water, water coning is severe because bottom water may travel through high permeability fractures. The situation can be especially common if the fracture system is extensively developed. A horizontal well can enhance the reservoir contact and increase the possibility of meeting more fractures, thereby ensuring the economic oil productivity. However, horizontal wells are more easily subject to water breakthrough problems due to more fracture network connections. The coning water production reduces the oil production significantly, which has become a serious problem in many oil field applications. As of 2000, oil companies produced an average of 3 barrels of water for each barrel of oil from the depleting reservoirs, more than $40 billion was spent dealing with unwanted water per year [10]. The production of water was reported to be 249 million B/D in 2005[11]. Therefore, it is necessary to delay and minimize water coning for both technical and economic considerations [12-14]. Many different methods and materials are available to solve excessive-water-production problems. These methods can be broadly categorized as chemical or mechanical. Polymer, foam, and gels are typical chemical plugging agents [15, 16]; packers, bridge plugs, and patches are examples of mechanical techniques. Each of these methods works well for certain type of water-coning problem [17]. Therefore, to achieve an effective treatment when dealing with the water production problem, the nature of the problem should be understood correctly [18]. Based on the conceptual consideration related to the treatment difficulty, the water production problems are summarized into four categories, among which the linearflow problems are water coning problems caused by linear-flow features (e.g., fracture, fracture-like structures, narrow channels behind pipe, or vug pathways). Problems such as casing leaks, flow behind pipe, 2D coning and naturally fracture system leading to an aquifer, are normally effectively solved with gelants (i.e., the fluid gel formulation before significant crosslinking occurs). For the other problems, performed or partially formed gels (i.e., crosslinking products that will not flow into or damage porous media) are the best solution [17]. However, the approach to solving linear flow problems are fundamentally different from solving radial flow problems in reservoirs without fractures. Especially for gel treatment, the gel properties, placement procedures and the optimum volume of gel placed differs greatly from those in radial flow treatment. Hydrocarbon zones must be protected during gelant placement for radial flow problems [19]. Therefore, it is critical to decide whether the flow around wellbore is linear or radial. Several methods are available to judge whether the flow near wellbore is linear (with fracture-like features) or radial (in an unfractured matrix or rock), such as Darcy equation method, core and log analysis, interwell tracer tests and pressure transient analysis [20-23]. Compared to cement and carbonates, gelant can easily flow into the porous media and seal the hydrocarbon-bearing zone sufficiently. The shutoff function of gelant and gel is to deeply penetrate into a reservoir and plug the narrow channels or micro-fractures near the zone to be shut-off [24]. Therefore, gels involving gelant injection are frequently


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used to treat excess-water-production problems in unfractured reservoirs [25, 26]. However, when the water zone is located at the bottom or above the oil zone, crossflow occurs between hydrocarbon strata and water zone, and gelant will cross flow and damage the oil-producing zones without effectively plugging water production zone. Therefore, the gel treatment will be meaningless no matter how much gelant is injected [27]. Gel treatment can be applied in both production and injection wells to treat water production problems in unfractured reservoirs with effective barriers to crossflow [28-30]. Many polymers and gels can reduce the relative permeability to water to a greater extent than that to oil/gas. This property is called disproportionate permeability reduction (DPR) [31, 32]. The DPR property is critical to the success of gel treatments in production wells located in hydrocarbon zones that are not effectively protected during gelant placement [33, 34]. The DPR property is of value only when high hydrocarbon saturation zones are distinct from the offending excess-water-producing zones. In other words, DPR will not alleviate water production in unfractured reservoirs that effectively has only one zone [35]. There are two technical obstacles preventing this gel treatment being successful in unfractured reservoirs without zone isolation. Firstly, the residual resistance factor to oil (Frro) must be less than 2, while the residual resistance factor to water must be greater than 10 [17]. Secondly, Frro less than 2 is hard to achieve because low Frro value means incomplete gelation which is severely subjected to pH, salinity, temperature and other factors. It is difficult to predict and control the gelation stage to obtain the desired Frro in consideration of the complex reservoir conditions [36]. The performance of DPR property in fractured reservoirs is different from that in unfractured reservoirs. DPR conformance improvement treatments can be easily applied in hydraulically or naturally fractured reservoirs. Basic engineering calculations [37] reveal that currently gel treatments with a DPR property are far more practical when treating linear flow problems (e.g., fractures) than radial flow problems (e.g., wells without fractures). When treating with fractures, the successful application of gel treatment only has two requirements. Firstly, the reduction of permeability to water is more than that to oil. In other words, the residual resistance factor of oil is smaller than that of water. Secondly, the distance of gelant leak-off from the fracture surface controllable. These requirements ensure the timely recovery of oil productivity. The gel is placed and functions within the matrix rocks adjacent to fractures [38]. If gelant penetration distances are too large, the pressure gradient may be too small to allow oil to initiate the flow through the gel. The block ability of gel to water is determined by the product of leak-off distance and the residual resistance factor provided by the gel [17]. The caused resistance to water and oil is a critical issue for both linear and radial flow problems during DPR application. Therefore, it is necessary to investigate the mechanism of DPR. Understanding the mechanism enables us to figure out the right technique to improve the gel treatment performance and make full use of DPR. The general DPR process can be described as follows: after porous media is treated with cross-linked gels, the permeability will drop to a low level. Afterward, the oil flow channels develop as the oil penetrate into the gel-filled pore spaces. However, the permeability to subsequent water will be exceptionally low even the oil permeability has increased to a great value. There are a number of works focusing on the mechanisms of oil permeability development and DPR [39-49]. Dawe and Zhang’s visual


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microscale studies reveal that oil and water pass through the gels by different mechanisms. Oil passes the gel by fingering from the center of the pores and widens the pathway by taking away some water from inside the gel and dehydrating the gel, whereas water passes a gel by diffusing into and swelling the gel [50] . Liang et al. [51] examine several possible explanations about DPR, demonstrating that gel shrinking and swelling is not likely to be responsible for DPR. Wettability plays a role in DPR yet with limited influence, and they suggest that the segregation of oil and water pathways may instead play the domination role in DPR. Nillson et al. [52] put forward a mechanism with segregated pathways for oil and water and the preferential pathways for oil and water are controlled by wettability and partially by pore size. Liang and Seright [53] came up with a new point that if the gelant matches the wetting phase, the wall-effect model results in the DPR. If the gelant matches the non-wetting phase, the droplet model accounts for the DPR. Willhite et al. [54] held that the gel dehydration mechanism creates new oil flow channels and the brine flows primarily in the same flow path as oil. The trapping of oil leads to the DPR. Nguyen et al. [55] studied DPR mechanism in sand packs treated with Cr(III)-acetate-HPAM gels. They claim that oil restores permeability by dehydrating and displacing of gels and reconnection of residual oil ganglia. And the trapping of residual oil is the main reason leading to DPR. Using X-ray, Seright et al. [56, 57] showed that dehydration is the primary reason for the oil permeability increase. The permeability to water is extremely low because gel and oil primarily flow in the same path, but the gel rehydration and swelling partially close the path, thus the water must flow through the gel itself. With respect to the oil permeability development mechanism, researchers mainly focus on the displacement mechanism [40, 57, 58] and dehydration mechanism [49, 50]. None explanation is fully convincing and more works should be done to further verify the mechanism. As for the mechanism of DPR, possible explanations, such as pathway segregation, residual oil blocking, wall effect model, restricted pore-throat model, and flowing through gel itself because of gel swelling, are always able to find their own basis. However, none of these proposed mechanisms have been widely accepted to be the primary cause for DPR. Therefore, more investigations should be conducted to figure out the mechanism of DPR and the primary cause. In order to visualize DPR at the pore level, the NMR scanning technique is adopted in this work. NMR, as a non-destructive technique, has been applied to monitor the properties of petroleum reservoir fluids [59]. Specifically, it can be used to determine the components group abundances in liquids derived from petroleum and coal using selected multiplet 13C NMR spectroscopy [60]. It can also be applied to investigate fluid properties (i.e., wettability, saturation, and viscosity) [61, 62] and several rock properties (i.e., rock permeability, pore structure distribution, producible porosity, and the capillary pressure) [63-66]. Also, NMR is widely used in the well logging [67]. NMR shows a good application value in the petroleum industry. Several works investigate spontaneous imbibition using nuclear magnetic resonance [68-70], we previously studied the oil saturation development behind spontaneous imbibition front using NMR T2. NMR T2 can reflect the oil/water saturation changes in different pore sizes in the permeable medium [71]. Overall, the main purpose of this paper is to study the dominant mechanisms of oil permeability development and DPR using core flooding and NMR. The oil/water core flooding process that is scanned


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by Nuclear magnetic resonance (NMR). This scanning reflects the change of phase saturation, which enables us to have an insight into the change behaviors of oil/water flow pathways. Thereby, NMR results of core samples with different permeability are discussed to investigate the mechanisms of oil permeability development and DPR. In a companion paper, we studied the mechanisms by combining core flooding, NMR, and microscopic glass-etched model [72]. Our work will focus on the NMR scanned results of core samples with different permeabilities. This helps to further explore the effect of permeability on the gel-phase change. Also, this helps to further demonstrate the superiority of NMR scanning as a technique for studying phase interaction and caused flow behaviors associated with geltreatment. All the above cognition practice will deepen the understanding of DPR mechanisms and potentially improve the utility of polymer gels with a DPR property. 2 EXPERIMENT 2.1 Experimental materials Polyacrylamide polymers have been used for years to reduce the water production in producers and mobility control in injectors. What makes polyacrylamides distinctive for water shutoff is their ability to reduce the permeability to water more than to oil [32]. Sydansk (1990) developed the aqueous gels by crosslinking polyacrylamide polymer with a Cr (III)-carboxylate-complex crosslinking agent. By adding trivalent cations to form a solid-like gel structure, the cross-linked polymer provides greater reductions in permeability than uncross-linked polymers [8]. The gel technology has been tested in numerous oilfields and yields effective conformance control [73-75]. Our work is based on the cross-linked polyacrylamide gels. In the experiments, the gel contains 0.3% HPAM, 0.4% Cr (III) acetate, and 0.3% NaCl. The hydrolyzed polyacrylamide polymer (HPAM) has a molecular weight of approximately 12000 kDa, with 25% hydrolysis degree and 98 wt % purity. The sandstone cores are 7.1cm long and 2.51cm in diameter; the two core samples have the absolute permeability of 2.3 Darcy and 0.8 Darcy respectively. 2.2 Experimental procedure Before the gelant injection, the cores were fully saturated with water. Later, 6 pore volumes (PVs) of Cr (III)-acetate-HPAM gelant were injected with a constant pressure gradient of 48.6psi/ft, and the cores were shut in at 50℃ for 24 hours to allow gelation.


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ISCO pump Valve Formation water

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Fig. 1 Apparatus Schematic of NMR T2 scanning for DPR experiments [64, 71] As shown in Fig. 1, the first part of the experimental system is the core flooding system. The ISCO pump provides constant injection rates during the oil/brine injection. The pressure sensor detects the pressure gradient. In every 10 or 20 PVs liquid injection, the flooding process is suspended for T2 scanning. The second part is the nuclear magnetic resonance system. The core samples are inserted into the NMR probe for T2 scanning and then will be reset in core holder for the subsequent flooding. The experimental procedures of the NMR T2 scanning for DPR experiments include the following phases: a. b. c. d. e.

Inject the fully-fluorinated oil with a constant speed. Stop the oil injection for T2 scanning in every 10 PVs injection. Stop the oil injection, T2 scanning at a different time. Inject the brine after 110 PVs oil injection. Stop the water injection for T2 scanning in every 20 PVs injection.

2.3 Nuclear Magnetic Resonance (NMR) T2 test [76] The mechanisms of NMR have been detailed in our previous work [71]. Here we make a simple description again for a better understanding of NMR scanning. In the oil industry, hydrogen nuclei (1H) is popular in most fluids, which makes it an ideal nucleus for NMR measurement. Therefore, "Nuclear" refers to hydrogen nuclei (1H) here, which has a magnetic moment (tiny bar magnet). "Magnetic" means the instrument providing the magnetic field. Under certain conditions, a strong interaction between the hydrogen atom and magnetic field will be generated. This characteristic is called "nuclear magnetic


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resonance". It is known that water and oil are rich in 1H and 1H will display different distribution patterns under different conditions (Fig 2).

Field B

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Fig. 2 The schematic diagram of nuclear magnetic resonance [71] When a core sample, saturated with oil/water, is placed under natural conditions, the tiny bar magnets of hydrogen nuclei will show a random distribution. And the sample has no magnetic property. However, if the sample is placed in the static magnetic field, the tiny bar magnets will head to the same orientation. The magnetic moment synthesis of each hydrogen nucleus is presented as a macroscopic magnetization vector. The magnitude of the magnetization vector is proportional to the number of the free hydrogen nuclei that can interact with the magnetic field, which is proportional to the fluid volume. In the NMR T2 spectrum, the signal amplitude is a representative of the macroscopic magnetization vector. Therefore, the larger the signal amplitude is, the larger the free fluid volume is. The signal amplitude is the ordinate of the T2 spectrum, and relaxation time is the transverse coordinate of NMR T2 spectrum. The magnitude of relaxation time reflects the force that the fluid is subjected to. For single phase system, the magnitude of relaxation time reflects fluid volume with respect to the relaxation time. Generally, the longer the relaxation time is, the larger the pore size is, and the relaxation time and pore radius are positively correlated [77]. In our experiments, what we concern is not the exact value of pore size but the oil saturation change, so we take the relaxation time roughly as the pore size. Since both oil and water contain hydrogen nuclei, it is difficult to separate them from the magnetic signal directly. Two approaches can be adopted to solve this. The first is to block the water signal by adding paramagnetic MnCl2 to the water. The second is to block the oil signal by replacing oil with fullyfluorinated oil, where the hydrogen nuclei have been fully replaced by fluorine. In this study, we employ the second method to block the oil signal because the Cr(III)-acetate-HPAM gelant is sensitive to MnCl2. Gelation will be stopped by MnCl2 with the concentration of over 20000g/L[78].


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3 RESULTS AND DISCUSSIONS 3.1 Disproportionate Permeability Reduction Behaviors 0.6

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Fig.3—Permeability curves to oil and water after gel placement. The left image is the core with a permeability of 2.3 Darcy [72]. The right image is the core with a permeability of 0.8 Darcy. The red curve for the 2.3-Darcy case shows that the oil permeability increased gradually from 90 mD to 505 mD during the 110PVs oil injection. Meanwhile, the change rate of oil permeability decreased as the oil flooding continued. After the oil injection, subsequent water was injected and the permeability to water dropped down sharply from 500 to 40 mD, as the blue curve shows. The permeability to water maintained a constant value during the next 90 PVs water injection. Compared to the 2.3-Darcy case, the oil permeability curve in 0.8-Darcy case displays a similar pattern of change during the 100 PVs of oil injection. The oil permeability increased gradually and the oil permeability gradient decreased as the oil flooding proceeded. During subsequent water injection, the permeability to water also decreased sharply from 130 mD to an extremely small value and maintained a constant value. In the 2.3-Darcy case, the mechanism change leads to the oil permeability gradient decline at about 7 PVs. In the literature review, oil pathways evolution is believed to be attributed either to gel displacement mechanism or gel dehydration mechanism [58]. Before 7 PVs oil injection, the gel displacement mechanism dominates in the oil permeability development, later, gel dehydration mechanism overtakes [72] . Another evidence for the domination of gel displacement mechanism is gel production at the outlet. Compared to the 2.3-Darcy case, the oil permeability gradient in 0.8-Darcy case also shows a similar trend, so we assume the decline is also caused by the same reason as the 2.3-Darcy case. However, more work should be done to verify this assumption and to see their difference in NMR results. For the 2.3-Darcy case, when the oil injection reached 100 PVs, we paused the oil injection and carried out the NMR scanning at a different shut-in time. When we resumed the oil injection, a noticeable drop in oil permeability was observed within 3 PVs oil injection. Gel rehydration is proved to account for the slight reduction of permeability to oil [58, 72]. For the 0.8-Darcy case, when oil injection reached 50 PV, we stopped oil injection for 14 hours, after which a slight fall in oil permeability occurred similarly. We still assume the gel rehydration is the primary cause of the decrease of oil permeability. However, as the


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permeability of the two cases is different, further comparison of their NMR T2 curves should be considered. 3.2 Mechanisms of Oil Permeability Development In this section, we compare the NMR results of the core samples with different permeabilities to study the mechanisms of oil permeability development and DPR. All the NMR data has been processed using Medellin’s NMR inversion method [79] to eliminate the ringing effect of primary NMR data. 50

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Fig. 4— NMR T2 scanning curves at different PV of oil injection. The left image is the core with a permeability of 2.3 Darcy [72]. The right image is the core with a permeability of 0.8 Darcy. Take the NMR T2 curves after gelation as an example. There are two high peaks in the 2.3-Darcy case where the high left peak means a large amount of fluid existing in small pores and a wide-range distribution of small pores. However, in the 0.8-Darcy case, the left peak is negligible. The ratio of small pores is related to the separation of rocks. When the relaxation time is larger than 400ms, the signal amplitude in the 0.8-Darcy case shows no value while there is a certain value in 2.3-Darcy case. As the relaxation time roughly represents the pore size, we can approximately conclude that the maximum pore in 2.3-Darcy case is larger. Signal amplitude represents the volume ratio with respect to the relaxation time. For the comparison at 100ms, the peak signal amplitude in 0.8-Darcy case is twice of that in 2.3Darcy case. What is more, the area under T2 distribution curve with relaxation time larger than 100 ms in 0.8 Darcy case is larger than that of 2.3-Darcy case. This doesn’t mean the more large pores in 0.8-Darcy case, because different core sample has a different correlation between relaxation time and pore size. The left picture in Fig. 4 shows the NMR T2 scanning curves for the 2.3-Darcy case at different PV of oil injected. A sharp signal decrease in large pores happened when oil injection reached 7PV, at which there is a noticeable decline of oil permeability gradient. However, no more noticeable signal amplitude decrease in large pores was detected during further oil injection. It has been proved that a gel displacement mechanism in large pores is the primary reason for oil pathway development initially [72]. As the signal amplitude is proportional to the fluid volume, this signal decrease in large pores means the replacement of gel by fully-fluorinated oil, which has no signal during NMR T2 scanning. The production of some gel at the outlet supports this conclusion further. With the proceeding of oil flooding, there is an


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obvious increase in signal amplitude in small pores while the change in large pores is inconspicuous. As paramagnetic Cr(III) can greatly shorten the relaxation time, the relaxation time of the Cr (III)-acetateHPAM gel is shorter than free water. During NMR tests, if echo time is too large, a portion of the signal with short relaxation time relaxes so fast that the instrument cannot detect them. Therefore, for the same volume of gel and water in small pores, the detectable NMR signal of water is possible to be larger than gel. When free water is pushed our of gel in small pores, the total NMR signal is possible to become more. As the Cr (III)-acetate-HPAM gel can dehydrate under oil phase pressure, more water will be pushed out of the gel and be trapped in small pores with the going on of oil flooding. Therefore, the increase of free water in small pores is responsible for the gradual increasing of signal in small pores. For the 0.8-Darcy case, signal plummeted in large pores during the first 10 PVs of oil injection, while no obvious change occurred in small pores. During this process, some gel was also produced at the outlet. Based on the discussion in 2.3-Darcy case, we have acknowledged that the gel displacement mechanism is the primary mechanism for oil permeability development initially. However, as the oil injection continued, signal drop still occurred in large pores during another 40 PVs of oil injection with no change in small pores. The signal amplitude behavior is different from that in the 2.3-Darcy case, where signal amplitude jumps in small pores while the change in large pores is inconspicuous. In the 2.3-Darcy case, the decline of oil permeability gradient results from the mechanism change. The displacement mechanism entails a high oil permeability gradient while the subsequent dehydration mechanism leads to a smaller oil permeability gradient. The oil pressure gradient decreased at about 10 PVs of oil injection, if the dehydration mechanism is also the primary mechanism causing oil permeability development after 10 PVs of oil injection, the T2 curves change pattern during another 40 PVs of oil injection should be different from that during the first 10 PVs. Notice the 0.8-Darcy case, the amplitude peak dropped from 85 to 55 during the first 10 PV of oil injection, while the peak value decreased from 55 to 42 during another 40 PV of oil injection, indicating slower decline speed of the signal. This is consistent with the smaller oil permeability gradient during another 40 PVs of oil injection. Therefore, we conclude that the gel dehydration mechanism is the main mechanism in this phase. In terms of the obvious decrease in large pores, as small pores are in the minority in the 0.8 Darcy core, the dehydration mainly happened in large and moderate pores, and it was difficult for the water dehydrated from the gel to stay in the oil flow channels created by oil phase pressure. The water dehydrated from the gel was displaced out and the nonsignal fully-fluorinated oil took the pore space previously occupied by the dehydrated water, so the signal amplitude in large pores kept falling. It is possible that a small portion of dehydrated water is left in the flow channels, whereas its volume is too small to offset the signal decrease. The signal change in small pores is too inconspicuous to mention.


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Fig. 5— NMR T2 scanning curves at different PV of oil injection. The left image is the core with a permeability of 2.3 Darcy [72]. The right image is the core with a permeability of 0.8 Darcy. Figure 5 is another set of NMR T2 scanning curves during the further oil injection. From the discussion in Fig. 4, the dehydration mechanism was responsible for the oil permeability development in both cores at this stage. As the oil flooding proceeded, the permeability to oil kept growing. For the 2.3-Darcy case, the signal amplitude in small pores increased gradually while no distinct change occurs in large pores. For the 0.8-Darcy case, the signal in large pores kept decreasing at a very low speed. The peak value declined from 40 to 37during the 30 PV of oil injection. However, the signal change in small pores is too inconspicuous to mention. In conclusion, gel dehydration mainly occurs in small pores for the 2.3-Darcy case while gel dehydration mainly happens in large and moderate pores for the 0.8-Darcy case, indicating that the gel dehydration becomes more and more difficult. 40

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Fig.6— NMR T2 scanning curves at different shut-in time duration. The left image is the core with a permeability of 2.3 Darcy [72]. The right image is the core with a permeability of 0.8 Darcy. When 100 PVs of oil was injected, we paused the oil flooding and scanned the core samples at a different shut-in time. Fig. 6 plots a series of NMR T2 curves that demonstrate gel rehydration versus shut-time. For the 2.3-Darcy case, the signal amplitude decreased as the time went by, which is caused by the gel rehydration [72]. The dehydrated gel absorbed free water and rehydrate, the detectable NMR signal accordingly decreased. For a given equal volume in small pores, the detectable signal amplitude of free


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water is much larger than the mature gel, which accounts for the signal decline in gel rehydration. For the 0.8-Darcy case, the signal amplitude also dropped gradually. The gel rehydration in this case also suggests that some free water was left in the oil flow pathways because the rehydration happens only when the dehydrated gel meets free water. For both cores, when the oil flooding restarted, a noticeable decrease in oil permeability occurred. However, the permeability quickly recovered during another 3 PVs of oil injection. So we conclude that for both cores the gel rehydration can only partially reduce the permeability and the rehydrated gel can be easily extruded by the oil phase. For the 2.3-Darcy case, the signal amplitude started increasing after 10 PVs of oil injection, suggesting that the gel dehydrated again. However, for the 0.8-Darcy case, the rise in signal amplitude occurred in large and moderate pores, which is inconsistent with our conclusion in Fig. 4 and Fig. 5 that when the dehydration happens, the signal amplitude in large pores decreases. A possible explanation for this is that after the gel rehydration happened, the oil flow channels in large pores would deform. And the distribution of oil, gel and free water would turn more complex, so the free water dehydrated from the gel could not be displaced out immediately and completely, contributing to the slight increase in signal amplitude. As the oil injection continued, the signal amplitude in large pores gradually descended as shown in Fig. 5, demonstrating the free water dehydrated from the gel was displaced out from the flow pathways. 3.3 DPR mechanism After the oil flooding process, subsequent water was injected into the core samples and the corresponding NMR T2 curves were shown in Fig.7. 100

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Fig.7— NMR T2 scanning curves at different PV of water injected. The left image is the core with a permeability of 2.3 Darcy [72]. The right image is the core with a permeability of 0.8 Darcy. For the 2.3-Darcy case, compared to the NMR T2 curve when oil injection just reached 110 PVs, the signal of water flooding in both large and small pores show a clear increase, especially in large pores. Compared to the NMR T2 curve just after gelation, when 20 PV of water was injected the signal amplitude in large pores would immediately recover to the approximate value as that after gel gelation. The signal amplitude in large pores rose because the gel rehydrated and the fully-fluorinated oil


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previously occupied the large pore space was largely replaced by the rehydrated gel or free water. There is a large portion of residual oil left in the large pores. In fact, for a given equal volume, the relaxation time of free water is much larger than matured gel, therefore only little fully-fluorinated oil was displaced out because the increase of signal in large pores is approximate to that after gelation. Fig.3 shows that the permeability plumped from 500mD to 40mD as the water flooding started. The gel rehydration and high residual oil saturation are two important mechanisms for the DPR to water. Some water has to flow through the gel body and gel films [72]. Seright previously mentioned that the permeability to water through the gel is extremely low [58], so water’s low flow capacity through the gel is also a reason for DPR. With the increase of water injection, the signal amplitude in large pores and small pores remained unchanged. The permeability to water maintained a relatively constant value during the subsequent water flooding, indicating the termination of gel rehydration. For the 0.8-Darcy case, a gradual signal increase in large pores occurred as the first 30 PVs of water injection. This phenomenon is different from the signal change in 2.3-Darcy case where signal increased in both large pores and small pores. Moreover, the signal amplitude in large pores rebounded to the level close to the 2.3-Darcy case after gelation, while the signal amplitude in 0.8-Darcy case recovered to a value that is far less than the signal amplitude after gelation. A possible explanation is that as the oil pathways are narrower than that in the 2.3-Darcy case, the pathways would be further compressed when the gel rehydration happened, where much residual oil was left. So the ability of flow pathways to trap free water in this case is lower than the 2.3-Darcy case. Consequently, the gel rehydration and the trapping of free water only lead to a limit increase in signal amplitude in large pores. Besides, plenty of the residual oil was trapped in the flow channels, which, together with the expansion of rehydrated gel, will significantly block the flow pathways. Most water had to flow through the gel and gel films. Fig.3 shows the permeability dropped from 130 mD to 4 mD when the water flooding began and the permeability maintained as the water was steadily injected. In this case, high residual oil saturation, gel rehydration and the low permeability of gel relative to water are the main mechanisms of DPR. As water was injected, the signal amplitude in large pores slightly decreased after 30 PVs of oil injection. There are possible explanations for this phenomenon. First, the increase of fully-fluorinated oil in large pores. However, as no more oil was injected during this phase, this assumption is incorrect. Second, the decrease of the free water. The free water reduction resulted from the deepening of gel rehydration which led to gel swelling and pushed more free water out of the pore space. As the detectable NMR signal amplitude of free water is larger than that of mature gel in relatively small pores, further gel rehydration cannot offset the free water loss, decreasing the signal amplitude. The speed of gel rehydration, in this case, is slower than that in the 2.3-Darcy case. 4 CONCLUSIONS (1) Gel displacement in large pores is the primary reason for the oil permeability development initially. As oil flooding proceeds, the gel dehydration mechanism becomes dominant. For the porous medium of very high permeability, gel dehydration occurs in all pores; while for the porous medium with lower permeability, gel dehydration mainly occurs in large pores.


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

(2) Some free water dehydrates from the gel will be trapped in the pore space, which is more difficult for the porous medium with lower permeability. Gel rehydrates when there is no oil phase pressure gradient. The rehydrated gel can reduce the permeability to a limited extent and the oil pathways can be easily extruded by the subsequent oil injection. (3) The gel rehydrates abruptly when meeting water and the permeability to water will be significantly reduced. The reasons for DPR include the gel rehydration that blocks the flow channel available to water, the high residual oil saturation which greatly blocks the available flow channels, and the low permeability of the gel relative to water. A large portion of water has to flow through the gel or gel films because of gel rehydration and residual oil retention. As for the low-permeability porous medium, gel rehydration mainly happens in large pores, while gel rehydration occurs in all space for the porous medium of high permeability when contacting water. (4) NMR T2 is an effective way to study phase interaction and flow behaviors associated with the gel treatment. Although the certain change in NMR T2 curves may happen because of the permeability difference, final conclusions for the mechanisms of oil permeability development and DPR are consistent. ACKNOWLEDGEMENTS The financial support from National Natural Science Foundation of China (Grand 51404280) and the Foundation of State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing (No. PRP/open-1707) is acknowledged. All the NMR data was processed The NMR inversion code used in this study was provided by Dr. David Medellin and Dr. Carlos Torres-Verdin at UT Austin’s Research Consortium on Formation Evaluation. The authors greatly thank Dr. Han Jiang at the University of Texas at Austin for performing NMR inversion. REFERENCES [1] Sheng, J. Modern chemical enhanced oil recovery: theory and practice. Gulf Professional Publishing. 2010. [2] Sorrell, S., Speirs, J., Bentley, R., Brandt, A. Miller, R. Global oil depletion: A review of the evidence. ENERG POLICY 2010; 38:5290-5295. [3] Bentley, R.W. Global oil & gas depletion: an overview. ENERG POLICY 2002; 30(3): 189-205. [4] Guo, T., Li, Y., Ding, Y., Qu, Z., Gai, N., Rui, Z. Evaluation of acid fracturing treatments in shale formation, ENERG FUEL 2017; 31(10): 10479-10489 [5] Zhang, L., Li, X., Zhang, Y., Cui, G., Tan, C., Ren, S. CO2 injection for geothermal development associated with EGR and geological storage in depleted high-temperature gas reservoirs. ENERGY 2017; 123: 139-148.


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Mechanism Study of Disproportionate Permeability Reduction Using

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