Effect of the Injection Pressure on Enhancing Oil Recovery in Shale

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Effect of Injection Pressure on Enhancing Oil Recovery in Shale Cores during the CO2 Huff-n-Puff Process When It Is above and below MMP Lei Li, Yao Zhang, and James J. Sheng Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b00031 • Publication Date (Web): 15 Mar 2017 Downloaded from http://pubs.acs.org on March 16, 2017

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Effect of Injection Pressure on Enhancing Oil Recovery in Shale Cores during the CO2 Huff-n-Puff Process When It Is above and below MMP Lei Li, a Yao Zhang, a James J. Sheng* a, b a

Department of Petroleum Engineering, Texas Tech University, Lubbock, TX, 79409, United States Southwest Petroleum University, Chengdu, China *Corresponding author: Tel: +1 806.834.8477, Email: [email protected] b

ABSTRACT In CO2 injection, there is a minimum miscibility pressure (MMP) above that CO2 can be miscible with oil so that oil recovery will be high. This paper is to investigate the effect of injection pressure on enhanced oil recovery in shale oil cores under huff-n-puff CO2 injection, when the pressure is above and below the MMP. We first estimated the MMP for a Wolfcamp oil using slimtube tests. The slimtube test results showed that the estimate MMP for the CO2-Wolfcamp crude oil system was about 1620 psi at 104 °F. After that, we conducted fifteen CO2 huff-n-puff experiments using three different Wolfcamp shale cores at pressures below and above the MMP. These pressures were 1200, 1600, 1800, 2000, and 2400 psi. Each huff-n-puff test has seven cycles. The huff-n-puff experiments for three cores showed that below the MMP, the injection pressure had a significant effect on enhancing oil recovery. Higher than the MMP, the increased pressure further increased the oil recovery until the injection pressure was about 200 psi higher than the MMP. In the extremely low-permeability shale oil cores, additional pressure is needed to push gas into the deeper core to be miscible with the crude oil inside the core. The results indicated that to have a high oil recovery in shale oil reservoirs during the CO2 huff-n-puff process, the injection pressure should be higher (at least 200 psi in this case) than the MMP estimated from slimtube tests.

1. INTRODUCTION According to a study sponsored by US Energy Information Admiration (EIA), the estimated shale oil in United States represents 26% of the total technically recoverable crude oil resources.1 The combination of horizontal well and hydraulic fracturing technologies have made it possible to produce shale oil economically.2 However, the oil rate declines sharply after a few months’ production. The primary oil recovery in shale oil reservoir is low due to the extremely-low permeability and small pore sizes. Thus, other EOR techniques have become a hot topic. CO2 miscible/immiscible flooding was tested first. However, the gas may easily break through to the producers due to the existence of hydraulic fractures, leading to a lower sweep efficiency.3 The CO2 huff-n-puff, which uses a single well as both the injection well and a production well, has been applied to shale oil reservoirs in recent years and has been demonstrated as an effective EOR solution in laboratory experiments.4-8 Numerous tests have been conducted to explore the effects of soaking time, depletion rate, the number of injection cycles, injection gases, and other variables.9-19 N2 and CO2 have both been used for the injection gas in previous studies. CO2 injection is more popular, primarily because CO2 develops multi-contact miscibility with crude oil at a low pressure.21-35 For conventional reservoirs, after reaching the minimum miscible pressure (MMP), the injection gas CO2 and the crude oil reach miscible condition through a multi-contact process at reservoir pressure. CO2 helps increase the oil sweep volume and displacement efficiency, which results in a high oil recovery. Thus, CO2 miscible flooding is an efficient and popular method in conventional reservoir production. However, when applying the CO2 gas huff-n-puff method to shale oil reservoirs, the 1 ACS Paragon Plus Environment

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effect of injection pressure on the performance of gas huff-n-puff EOR method has not been studied, when the pressure is above or below the MMP. Researchers have done some studies on injection pressure. Liu et al.27 proposed a hypothesis that immiscible injection is more favorable as the CO2 can penetrate into the reservoir to dissolve more oil with large contact area under immiscible conditions. Song and Yang30 compared the injection pressure of CO2 huff-n-puff process in tight cores with permeability range of 0.27-0.83mD. They found that the optimum injection pressure can be set near-miscible pressure. However, they claimed that a higher injection pressure results in a higher oil recovery even when the injection pressure higher than MMP in their new simulation study.31 In their experiments, they used different core samples to conduct four scenarios of displacement experiments. The difference of the core samples (the permeability, porosity, non-uniform distribution of the oil and heterogeneity of the core) may lead to a biased result. Also the permeability of the shale oil cores is usually less than 0.001mD. The large permeability core samples may perform rather differently from the shale cores. Gamadi et al.10 conducted CO2 huff-n-puff experiments on Eagle Ford and Mancos cores with mineral oil. They found that the oil production increased drastically when the conditions changed from immiscible to miscible injection and claimed that injection at a pressure higher than MMP does not have a strong effect on the ultimate recovery factors. However, in their study they didn’t construct the experiment to measure the MMP of CO2-mineral oil. Thus, their claim needs to be validated. Zhang32 conducted miscible coreflooding experiments on a Bakken core sample with an average porosity of 7.5% and permeability of 1.8 µd and recovered more than 70% of the OOIP. Other researchers did simulation studies to investigate the effect of miscibility on oil recovery. Schoaib and Hoffman found that miscible condition outperforms immiscible condition by increasing the oil recovery around 7% when applying continuous gas injection in Elm Coulee Field.33,34 The similar result was obtained by Dong and Hoffman when applying gas injection to Sanish Field in North Dakota.35 Chen et al.24 used UT-COMP to investigate the effect of reservoir heterogeneity in gas huff-n-puff. They observed that the CO2 performance is better when it remains in near-fracture region than diffusing deep into the formation. Lai et al.37 investigated the continues CO2 injection under three conditions: immiscible, near-miscible and miscible. They found that near-miscible can effectively develop shale oil. Wan and Sheng14 used CMG to study CO2 huff-n-puff injection. They indicated that if a higher pressure is used to reach full miscibility with the reservoir oil and more cycles are employed, a greater oil recovery can be expected. The above literatures reveal three opinions regarding the injection pressure during gas injection EOR in shale reservoirs: immiscible, near-miscible and the higher pressure the better. There are several problems existing in the previous studies. Firstly, in the experiment study, the cores they used are not exactly shale cores as their permeability are out of the range of shale cores. Secondly, the MMP of oil they used during the experiment is from simulation results instead of experimental measurement data. Thirdly, most of their results are derived from simulation study. As the results from the simulator can be affected dramatically by changing the input parameters, the simulation may not include all the EOR mechanisms during the gas huff-n-puff injection and the result may diverge from the true result. Thus, new experiment design is needed to represent the gas huffn-puff process and to investigate whether it is necessary to increase the injection pressure higher than the MMP when applying the CO2 huff-n-puff EOR method in shale oil reservoirs. The study began with measuring the MMP of a CO2-crude oil system. Every oil has a unique MMP with CO2 because each oil has a distinctive oil composition. During the miscible displacement, a mass transfer between oil and CO2 occurs by vaporization, extraction, or condensation. The crude oil and core samples used in this study are Wolfcamp crude oil and Wolfcamp shale core samples from the Permian Basin. The common methods of determining the MMP include empirical correlations, experimental 2 ACS Paragon Plus Environment

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methods, and simulation methods. The empirical correlations can be considered as the least accurate methods, as they were developed by fitting experimental data.38-51 When the injection gas or oil compositions are substantially different from those used to develop the correlations, the result may diverge significantly.52 The experimental methods include the slimtube experiments, the rising bubble method, and the vanishing interfacial tension method. However, the rising bubble and vanishing interfacial methods do not entirely include the vaporization and condensation multi-contact mechanisms.53,54 The sand-packed slimtube flooding equipment simulates the 1-D displacement of reservoir crude oil by CO2. During this process, the thermodynamic phenomena taking place in CO2-oil system are fully considered. Thus the sand-packed slimtube experiment is considered as the most accurate method to determine the MMP.54,55 The measured MMP using sank pack could be different from the real MMP in shale cores. Teklu et al.56,57 did simulation studies of MMP by using the multiple mixing cell simulation for the unconventional reservoir system, and they found that the MMP can be reduced by up to 600 psi for pore diameters less than 3 nm for CO2-Bakken oil system. Wang et al.52 used PC-SAFT calculation and found that 23.5% reduction is achieved for MMP of CO2-Bakken oil system when the pore width decreased to 3 nm compared with the bulk value. However, the pore size distributions in shale reservoirs are not uniform and the formations are heterogeneous.8 The study about the effect of single pore size on MMP has less practical significance in the production of shale oil. Until now, no feasible experiments can validate the MMP in unconventional reservoirs. As the MMP in conventional reservoir is easier to be measured and when applying gas huff-n-puff in shale reservoir the dominant parameter is the operation pressure. The main concern of this work is to investigate the relationship of injection pressure with MMP and provide a guide to design injection pressure to produce shale oil efficiently. To investigate the injection pressure effect on CO2 huff-n-puff EOR in shale oil reservoirs, a new study method was designed by including both slimtube experiments measuring the conventional MMP of a CO2-Wolfcamp crude oil system and the CO2 huff-n-puff experiments to test the effect of different injection pressures on enhancing the oil recovery in shale cores. The experiments reveal more accurate results by including all mechanisms such as pressure gradient, oil swelling, oil viscosity decline, miscibility and gas diffusion during the gas huff-n-puff. By comparing the results from slimtube experiments and gas huff-n-puff tests, the effective injection pressure was achieved. A compositional radial model was built and validated with experimental data to simulate the gas huff-n-puff process in shale cores. The pressure effect in shale cores was also analyzed by simulation to better understanding the experiment results.

2. EXPERIMENTAL 2.1. Experimental Materials. CO2 gas with purity of 99.999% and Wolfcamp dead crude oil were used in the slimtube experiment. Table 1 illustrates the main properties of the Wolfcamp dead crude oil. The oil composition was tested using a Gas Chromatography/Mass Spectrometer instrument and is listed in Table 2. As shown in Figure 1, core plug samples from Well #SSH 31, Wolfcamp formation in Apache's Lin field were used in the CO2 huff-n-puff experiment. The diameter and the length of the core are 1.5 inches and 2 inches, respectively. The measured average helium porosity was 6% - 8% and the nitrogen permeability ranges 300 nD to 500 nD. Table 1. Properties of Wolfcamp dead crude oil. Density at 72°F (g/ml)

Viscosity at 72°F (cp)

API Gravity (°API)

0.796

3.58

46.7

Table 2. Mole percent data of Wolfcamp dead crude oil. 3 ACS Paragon Plus Environment

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Component

Percent

Component

Percent

Component

Percent

C3H8

0.009%

FC9

8.339%

FC21-22

2.268%

IC4

0.004%

FC10

8.336%

FC23-24

1.040%

NC4

0.005%

FC11-12

11.786%

FC25-26

1.727%

IC5

1.349%

FC13-14

9.413%

FC27-28

1.050%

NC5

1.349%

FC15-16

6.787%

FC29-30

0.501%

FC6

4.588%

FC17-18

4.940%

FC31-36

0.952%

FC7

10.684%

FC19

2.148%

FC37-40

0.937%

FC8

12.295%

FC20

1.284%

FC41+

8.210%

Figure 1. Wolfcamp core plug samples used in the CO2 huff-n-puff experiments (the picture taken after oil saturation).

2.2. Slimtube Experiments. A sand packed slimtube apparatus was utilized to perform the experiments as shown in Figure 2. An 80-foot long, 0.25-inch diameter stainless steel tube was used, and it was packed with 100-150 mesh Ottawa sand and held in place by a 325-mesh stainless steel screen at each end. The slimtube had a porosity of approximately 35%. The slimtube column’s small diameter and great length created an environment where viscous fingering is eliminated or extremely minimized by transverse dispersion. There were three accumulators in the air bath. Accumulator 1 contained toluene which was used as the solvent to clean the slimtube. Accumulator 2 held crude oil one to saturate the column. Accumulator 3 was the container for the injection solvent; here, CO2 was used in our study. To determine the MMP pressure, normally at least two tests are performed at pressures below the expected MMP and two tests are performed above the MMP. The data was plotted for oil recovery versus pressure and where the two lines intercept is the MMP point.

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Figure 2. Schematic of the set up for the MMP determination apparatus using the slimtube technique.

To prepare and conduct each experiment, three main tasks were followed: slimtube cleaning, saturating with oil, and solvent injection. The following are the main steps to conduct one slimtube experiment: 1. Slimtube cleaning: To guarantee the porous media is clean and dry before each run, 2 to 3 pore volumes (PV) of toluene are injected to clean the oil in the slimtube. Once the produced solvent is clear, CO2 gas can be injected through the column to dry out the column and remove the solvent. The slimtube can also be heated while gas is being injected to remove the solvent quickly. The slimtube coil is then weighted and compared to its original weight to verify that it is fully clean and dry. If the weight difference is more than 0.2 gram, the cleaning and drying procedure is repeated. 2. Toluene injection: Vacuum the slimtube for several hours. Inject toluene in accumulator 1 to the column at the rate of 0.2 cc/min, gradually increasing the back pressure (BPR) to the designed test pressure. 3. Crude oil Saturating: Ensure the pressure is set at the designed pressure and test temperature (104°F). Saturate the slimtube with crude oil at a rate of 3 cc/hr. The minimum injection pore volume is 1.2 PV. After observing lots of oil coming out from the end, stop injecting crude oil and make sure the slimtube is fully saturated with crude oil. 4. CO2 injection: Maintain the solvent (CO2) at the test temperature and at a pressure 10-50 psi higher than the test pressure. Start displacing the oil with CO2 with the injection rate of 2 to 4 cc/hour at desired pressure until 1.2 PV has been injected.


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Finally, the sand packed column, and the residual oil contained therein, are weighed and the volume of residual oil is calculated from the weight difference. The oil recovery can be calculated by using the weight of the produced oil divided by the total oil weight inside the slimtube. 5. Repeat Steps 1 to 4 at different pressures until 90% recovery or greater is achieved. 2.3. Gas Huff-n-Puff Experiments. Based upon the result of MMP, fifteen series of CO2 huff-npuff experiments were implemented on three different Wolfcamp shale core samples at the pressures below and above MMP, which were 1200, 1600, 1800, 2000, and 2400 psi. Each huff-n-puff series has seven cycles. The cores were saturated with Wolfcamp crude oil. The huff-n-puff injection equipment is shown in Figure 3. Accumulator 1 is used to store the injection gas and increase the gas injection pressure. The core samples are put in Accumulator 2. Accumulator 3 contains crude oil which is used to saturate the core plugs. The huff-n-puff experiment, similar to the one in our previous research, is divided into two sections including saturating the core sample with crude oil, and conducting the gas huff-n-puff test.17

Figure 3. Schematic of the set up for the CO2 huff-n-puff experiments.

Core saturation experimental procedure: 1. The core samples were named and dry weighted (Wd) after putting them in a 120°C oven for one day. 2. The core sample was placed in Accumulator 2, and was then vacuumed for one day. 3. The vacuum pump was then turned off. The crude oil was then injected into Accumulator 2. After the core was completely soaked with crude oil, 2,000 psi of pressure was maintained in the vessel for 2 days. Saturated oil weight in each core was calculated using the difference between the core dry weight (Wd) and saturated weight (Ws). After saturation, the crude oil was poured out from accumulator 2 and the core sample was put back. The huff-n-puff process was then started. Huff-n-puff experimental procedure: 1. Check the valves and inspect for leaking problems before conducting the gas injection process. 6 ACS Paragon Plus Environment

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2. Set the air bath temperature at a constant temperature (104 °F was used in our experiment). Inject gas into the accumulators 1 and 2. The syringe continuous pumping system will suppress the gas in Accumulator 1 to Accumulator 2 to increase the injection pressure to our designed pressure. Shut in the well when the pressure gauge reaches the designed pressure. 3. Allow 6 hours of soaking time to allow gas to dissolve into the oil. 4. After soak period finishes, release the internal pressure to the atmosphere pressure of 14.7 psi. 5. Wait for 6 hours until the core weight will not change, weigh, and record the core sample again as Wi. 6. Carry the second cycle of gas injection immediately after the first cycle, a third cycle after the second, and so on. The same procedures should be repeated in subsequent cycles using a similar manner to the first one. Each sample should be weighed and recorded after each cycle to calculate the oil recovery with its weight differences using the following equation:

= × 100%

(1)

3. SIMULATION METHOD A radial coordinate model with a two-dimensional radial cross section (r-z) and compositional reservoir simulator (CMG-GEM) were used to simulate the cyclic CO2 injection experiment. The accumulator had a diameter of 2.4-inches and height of 5.6-inches. The surrounding annular volume between the accumulator and core represented the fracture volume. All faces of the core sample were open during the gas injection, soaking, and production stages. Figure 4 shows the process of the model build up. In the experiment the core was in the center of the accumulator, and during the experiment the volume between the core and the accumulator was fully saturated with CO2. Thus, in Figure 4 (b) the core represents the matrix, and the volume between the core and accumulator represents the fracture space. Based upon this simplification, the compositional radial model in Figure 4 (c) was built to simulate the process of our experiment. The radial model has 26 gridblocks in the r direction and 24 gridblocks in the z direction. To separate the output of shale matrix and the surrounding fracture, we divided the simulation domain into two sectors. The shale matrix was set as sector 1 covering grid blocks from 1 to 20 in the r direction, and grid blocks from 7 to 18 in the z direction. The matrix permeability is assumed as 0.0005 mD. Fracture space with the permeability of 1000 mD was set as sector S2 and it includes the other grid blocks except for sector S1. Two wells (One producer, and one injector) located at the same grid blocks (1, 1, 1) were used to simulate the cyclic gas injection process in the shale cores. The injection well was constrained to the maximum injection pressure of our designed pressure and the maximum surface gas rate of 10 MSCF/day. The constraint was automatically changed to the other one if either of the two is violated. The production well was restrained to the minimum bottom-hole pressure of 14.7 psi. This setting made it convenient to simulate the physical displacement process of the cyclic gas injection. The reservoir rock and fluid properties of the simulation model are shown in Table 3. The Peng-Robinson EOS fluid description for Wolfcamp crude oil and CO2 is presented in Table 4. The binary interaction coefficients of Wolfcamp crude oil with CO2 are described in Table 5. Based upon the literature review and history matching the experiment data, the CO2 molecular diffusion coefficient is set to be 4E-05 cm2/sec, and the other oil component diffusion coefficients are set to be 0.5,28,29,58-60


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Figure 4. Model build up process and radial simulation model with logarithmic refinement (legend is initial oil saturation).

Table 3. Reservoir and fluid properties used in the simulation model. Parameter

Value

Unit

Matrix permeability

0.0005

mD

Fracture permeability

1000

mD

Porosity

6

% -6

psi-1

Total compressibility

1×10

Initial core pressure

14.7

psi

CH4 injection pressure

2000

psi

Injection time

0.01

day

Soaking time

1

day

Production time

0.01

day

Temperature

95

̊F

Table 4. Peng-Robinson EOS fluid description for Wolfcamp crude oil with CO2. Components

HC

Pc(atm)

Tc(K)

Accentric Fac.

MW

Vc(l/mol)

Vol.Shift

CO2

0

72.8

304.2

0.225

44.01

0.094

0

C3-4

1

39.269

394.7228

0.1687

51.1105

0.230214

-0.07924

C5-8

1

29.8467

556.4605

0.3331

101.7772

0.402268

0.027859

C9-19

1

19.9401

692.5801

0.5833

185.1622

0.698281

0.128336

C20-40

1

11.4471

844.253

0.9918

352.9444

1.269132

0.225044

C41+

1

7.8659

950.8726

1.2629

513.5156

1.797165

0.276248

Table 5. Binary interaction coefficients of Wolfcamp crude oil with CO2. Component (HC)

CO2

C3-4

C5-8

C9-19

C20-40

C41+

CO2

0

0.12

0.115

0.115

0.115

0.115

C3-4

0.12

0

5.17E-03

2.02E-02

4.68E-02

6.67E-02

C5-8

0.115

5.17E-03

0

5.05E-03

2.16E-02

3.63E-02

C9-19

0.115

2.02E-02

5.05E-03

0

5.92E-03

1.47E-02


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C20-40

0.115

4.68E-02

2.16E-02

5.92E-03

0

2.01E-03

C41+

0.115

6.67E-02

3.63E-02

1.47E-02

2.01E-03

0

4. RESULTS AND DISCUSSION 4.1. Slimtube Experiment. Seven experiments at pressures of 1000, 1350, 1660, 1750, 1800, and 2000 were conducted and the cumulative recovery was measured after 1.2 PV CO2 was injected. The results are shown in Figure 5. The point where the slope changed occurred at 91% recovery, when the test pressure was 1620 psi. Therefore, this pressure is considered as the MMP for the CO2-Wolfcamp crude oil system. The four tests conducted above this pressure, at 1660, 1800, and 2000 psi, showed the complete miscibility between oil and CO2. Published empirical correlations for MMP were also used to estimate the MMP for different oils at temperature of 104 °F. These correlations use different parameters (such as reservoir temperature, molecular weight of C5+ / C7+, mole percentage of C1, API gravity, volatile and intermediate oil fractions, pseudo-reduced temperature, and molecular weight). The results are shown in Table 6. The table also shows a comparison between those predicted values with the slimtube measured MMP value by calculating the resulting difference (error). It was noticed that the correlations of Holm and Josendal, Glaso without a correction for C2-C6, and Johnson and Pollin predict the MMP relatively closer to our measured MMP. The difference comes from two aspects. Firstly, the empirical correlations were developed by fitting experimental data. When the injection gas or oil compositions are substantially different from those used to develop the correlations, the result may diverge significantly.52 Secondly, the Wolfcamp crude oil is a dead oil with much less light components. Therefore, those methods that do not consider the light oil fractions predict a value close to our measured MMP.

Figure 5. Results of slimtube experiments showing MMP at 1620 psi

Table 6. Published correlations’ results for estimating MMP at 104 °F. Method

Value, psi

Error, %

2655.4

63.91

Cronquist

2077.7

28.25

Eakin and Mitch44

3153.7

94.67

40

Alston

43


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Glaso (without a correction for C2-C6)42

1640.5

1.27

Glaso (with a correction for C2-C6) 42

3637.4

124.53

39

1600

1.23

38

1714.7

5.85

1263.1

22.03

2925.6

80.59

Holm and Josendal Johnson and Pollin

Yellig and Metcalfe

49

Yuan51

4.2. Gas Huff-n-Puff Experiment. The huff-n-puff experiments for these three core samples are shown in Figure 6. This figure illustrates that below the MMP, the oil recovery increases significantly with the increase of injection pressure. And the oil recovery still increases when the pressures are higher than the MMP. The estimated MMP from slimtube experiments is 1620 psi. In the gas huff-n-puff experiments, when the injection pressure increases from 1600 to 1800 psi, 10% more oil can be produced after 7 huff-n-puff cycles. However, when the pressure is higher than 1800 psi, the increase of pressure is unable to enhance the oil recovery in shale cores significantly. This phenomenon is observed from the huff-n-puff experimental results of all the three core samples. To analyze the pressure effect, the oil recovery changes of cycles from 5-7 for the three cores are shown in Figure 7. From the figure, a pressure at the intersection from the two straight lines in each sub-figures can be read. When the injection pressure is above this pressure, insignificantly additional oil can be recovered from the core. The pressures at the intersections for the three cores are all around 1800 psi. But the MMP from the slimtube tests is 1620 psi. Thus, this pressure is about 200 psi higher than the MMP. Because the MMP estimated from the huff-n-puff tests is different from the one measured from the slimtube tests, we name the new MMP as effective MMP (EMMP). The difference can be better understood by combining the simulation results. Figure 8 shows the history matching of simulation data with experiment data from core No.2. A good agreement between the simulation results and the actual experiment data is obtained for oil recovery, while a slight mismatch is found in cycles 1, 3 and 4. This may be caused by the non-uniform distribution in core matrix and the unavoidable experimental errors. The simulation results also illustrate that more oil is produced when the injection pressure increases from 1200 to 1800 psi. After 1800 psi the injection pressure has less effect on enhancing oil recovery. Figure 9 shows that the pressure in the central part of the core is lower than that near the surface. To reach a miscible condition in the central part, the injection pressure near the core surface must be higher than the MMP. The distributions of CO2 mole fraction in oil inside the core and the oil saturation at the end of soaking period in the seventh huff-n-puff cycle are presented in Figure 10 and Figure 11, respectively. The results reveal that both the sweep volume of the core and the CO2 mole fraction increase when the injection pressure is increased from 1200 psi to 1800 psi. When the pressure is increased from 1800 psi to 2400 psi, the CO2 diffusion increases, resulting in the increase of CO2 mole fraction in oil. The pressure distribution inside the core at different times are described in Figure 12. When the injection pressure is 1800 psi, the pressure inside the core builds slowly. It takes 100 mins to allow the pressure inside the core reaches the MMP. At the end, the system equilibrium pressure is about 20 psi less than the injection pressure. This phenomenon is less obvious in the high-permeability slimtube. Another difference between the huff-n-puff test and the slimtube experiment is that the gas flooding rate in the slimtube experiment is extremely slow to allow the gas fully miscible with oil inside the column. While in the huff-n-puff test, the pressure depletion fast during the puff period, the whole process may be at the condition that the pressure in most of the core is lower than the MMP. Therefore, for the best performance of gas huff-n-puff EOR, the injection pressure must be higher than the MMP estimated from the slimtube tests. Figure 10 illustrates that the extra pressure 10 ACS Paragon Plus Environment

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increases the gas sweep volume and allow the oil and gas reach miscible condition inside the core. After the pressure inside the core reach the miscible condition, the additional injection pressure further increases the gas diffusion. However, the oil recovery does not change significantly afterwards. To investigate the huff-n-puff process, the changes in pressure, oil saturation, gas saturation, and gasoil interfacial tension at a block (10, 1, 12) which is 0.375 inches to the fracture are plotted in Figure 13. During the fourth huff-n-puff cycle, gas saturation starts to increase, which means the injected CO2 penetrated this block since the fourth injection cycle. From the enlarged view of cycle 7, during the huff period, the pressure increases from 14.7 to 1600 psi, gas saturation decreases from 0.39 to 0, oil saturation increases from 0.61 to 1.0, and the gas-oil interfacial tension decreases from 22.5 to 0 dyne/cm. It illustrates that when the pressure reaches the MMP, the two phases becomes one phase (oil phase) and the interfacial tension becomes 0. During the puff period, the pressure decreases, the oil saturation decreases, the gas saturation increases, and the gas-oil interfacial tension increases again. From Figure 7, all three cores in cycles 5-7 show the EMMP of CO2 huff-n-puff is around 1800 psi. The experiment results illustrate that the injection pressure should be 200 psi more than the MMP of CO2Wolfcamp oil system to get a higher oil recovery during huff-n-puff EOR process, although the confinement effect of nanopores may reduce the MMP. Cumulative oil Recovery

0.8 Core No. 1

0.7 0.6 0.5 0.4

P = 1200 psi P = 1600 psi P = 1800 psi P = 2000 psi P = 2400 psi

0.3 0.2 0.1 0 0

1

2

3 4 Number of cycles

5

6

7

8

(a) Pressure effect on CO2 huff-n-puff performance (Core 1) 0.8 Core No. 2

0.7 Cumulative oil Recovery

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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0.6 0.5 0.4 0.3

P = 1200 psi P = 1600 psi P = 1800 psi P = 2000 psi P = 2400 psi

0.2 0.1 0 0

1

2

3


6

(b) Pressure effect on CO2 huff-n-puff performance (Core 2)


7

8

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0.8 Core No. 3

0.7 Cumulative oil Recovery

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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0.6 0.5 0.4 P = 1200 psi P = 1600 psi P = 1800 psi P = 2000 psi P = 2400 psi

0.3 0.2 0.1 0 0

1

2

3


6

7

(c) Pressure effect on CO2 huff-n-puff performance (Core 3) Figure 6. Pressure effect on CO2 huff-n-puff performance in shale oil core samples

(a) EMMP for core 1 at cycle 5

(b) EMMP for core 1 at cycle 6

(c) EMMP for core 1 at cycle 7

(d) EMMP for core 2 at cycle 5


8

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(e) EMMP for core 2 at cycle 6

(f) EMMP for core 2 at cycle 7

(g) EMMP for core 3 at cycle 5

(h) EMMP for core 3 at cycle 6

(i) EMMP for core 3 at cycle 7 Figure 7. Results of effects of pressure on oil recovery in different cycles (for the 3 core samples)


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80

60

Oil Recovery Factor, %

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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40

20

Simulation P=1200 psi Simulation P=1600 psi Simulation P=1800 psi Simulation P=2000 psi Simulation P=2400 psi

0

-20 0.0

0.5

1.0

1.5

2.0 Time (day)

Experiment P=1200 psi Experiment P=1600 psi Experiment P=1800 psi Experiment P=2000 psi Experiment P=2400 psi

2.5

3.0

3.5

4.0

Figure 8. History matching results for different injection pressures (using the experiment data from core No. 2).

(a) Schematic of the mechanism of pressure effect

(b) Pressure distribution in a core from Simulation (the pressure in the center of the core is lower than that near core surface) Figure 9. Mechanism of pressure effect during the gas huff-n-puff EOR process.


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Figure 10. The distribution of CO2 mole fraction in oil at the end of soaking time in the seventh injection cycle for different injection pressures (dotted line outlining the core area).

Figure 11. The distribution of oil saturation at the end of soaking time in the seventh injection cycle for different injection pressures.


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2,000

1,600

Pressure (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

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1,200

800

400

0 0.0

0.2 0.4 0.6 Distance to the core center (inches) t=0 t = 30 mins t = 90 mins

t = 10 mins t = 40 mins t = 100 mins

0.8 t = 20 mins t = 50 mins t = 110 mins

Figure 12. Pressure distribution inside the core vs. soaking time in the seventh huff-n-puff cycle.


1.0

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1.00

20

0.80

2,000

15

0.60

10

0.40

5

0.20

1,000

Pressure (psi)

1,500 Gas/Oil Saturation

Interfacial Tension ((dyne/cm))

Cycle 7 25

500

0 0.0

1.0

2.0 Time (day)

0.00 4.0

3.0

Interfacial Tension: 10,1,12 Oil Saturation: 10,1,12

0

Gas Saturation: 10,1,12 Pressure: 10,1,12

Enlarged view for cycle 7: 25

1.00

20

0.80

2,000

15

0.60

10

0.40

5

0.20

1,000

Pressure (psi)

1,500 Gas/Oil Saturation

Interfacial Tension ((dyne/cm))

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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500

0 2.94

0.00 3.04

3.14

huff

3.24 Time (day)

3.34

soaking

0

3.44

puff

Figure 13. Changes in pressure, oil saturation, gas saturation, and gas-oil interfacial tension at a block (10, 1, 12) which is 0.375 inches to the fracture (the injection pressure is 1600 psi).

5. CONCLUDING REMARKS


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In this study, a novel experiment design was proposed to determine the effective injection pressure for gas huff-n-puff EOR in shale reservoirs based upon the conventional MMP measurement and huff-n-puff gas injection experiments. The MMP of a CO2-Wolfcamp crude oil system was measured by slimtube experiments and CO2 huff-n-puff experiments were conducted when the injection pressure were below, near, and above the measured MMP. For a huff-n-puff experiment, the oil-saturated core sample was exposed to CO2 under some injection pressure, then the pressure was released to ambient pressure. The weight difference of the oil-containing core is used to determine the fraction of crude oil recovered. The experiment results show that the MMP of the CO2-Wolfcamp crude oil system in the slimtube packed with sand particles is around 1620 psi. The CO2 huff-n-puff results show that before reaching the MMP, the oil recovery increases with the increase in the injection pressure. After reaching the MMP, the increased pressure can further increase the oil recovery, until the injection pressure is higher than the effective injection pressure called EMMP for gas huff-n-puff. The effective injection pressure was 200 psi higher than the measured MMP. The main reason for this difference is that due to the ultra-low permeability of a shale core, there is a significant pressure drop from the core surface to the central part of the core. The injection pressure is at the core surface and this pressure is used to derive MMP. To make the gas and oil be miscible in the central part of the core, the injection pressure must be higher than the MMP measured from the slimtube tests. Another reason is that as the gas injection and production rate in an experimental huff-n-puff test are much higher than those in the slimtube tests, it is difficult to have a full miscibility condition in the whole core, especially in the central part of the core in the huff-n-puff process, compared with the slimtube test. The pressure distribution inside the core during the soaking time from numerical simulation clearly demonstrate the significant pressure difference between the core surface and the center. A high injection pressure near the core surface is needed to help gas diffusion and gas-oil miscibility, leading higher oil recovery during huff-n-puff CO2 injection. And this pressure is higher than the MMP as shown from the simulation results. This study helps explain the pressure effect during gas huff-n-puff process in shale oil reservoirs and provides a guide to design injection pressure to produce shale oil efficiently based upon the conventional MMP.

ACKNOWLEDGMENTS Wolfcamp crude oil component and Wolfcamp core plugs were provided by Apache Corporation. The work presented in this paper is supported by the Department of Energy under Award Number DEFE0024311.

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Effect of the Injection Pressure on Enhancing Oil Recovery in Shale

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