experimental study of co2 huff-n-puff process for low-pressure reservoirs

7/24/2019 Experimental study of CO2 huff-n-puff process for low-pressure reservoirs

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SPE-169235-MS

Experimental Study of CO2 Huff-n-Puff Process for Low-PressureReservoirs

J. Ma, University of Regina; X. Wang, and R. Gao, Yanchang Petroleum; F. Zeng, University of Regina;

C. Huang, Yanchang Petroleum; P. Tontiwachwuthikul, University of Regina

Copyright 2014, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Latin American and Caribbean Petroleum Engineering Conference held in Maracaibo, Venezuela, 2123 May

2014.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents

of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect

any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written

consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

CO2

-based EOR technology has been proven as an effective method to enhance light-oil recovery, while

to reduce CO2

emission. Miscible and near-miscible CO2

flooding have been extensively studied and

commercially applied in the past several decades; while CO2

huff-n-puff process did not gain too much

attention. CO2

huff-n-puff process may have better performance than CO2

flooding for a low-pressure

reservoir, in which reservoir pressure is far below the minimum miscible pressure (MMP), since the CO2

injection is able to build up the reservoir pressure, and the increased reservoir pressure will enhance the

mass transfer between the CO2 phase and the oil phase.

In this paper, 8 coreflood tests, totally 35 runs, are conducted to investigate the major factors affecting the

performance of CO2

huffnpuff in a low-pressure reservoir. The coreflood tests are conducted in a 984

mm-long composite core with an average porosity of 19.6% and an average permeability of 117 mD. The

reservoir pressure is 6.58 MPa, far below the measured MMP value of around 23 MPa. The effects of primary

operational parameters, such as CO2

injection rates, slug size, soaking time, injection pressure, pressure

depletion rates, and chasing gas (N2) on the huffnpuff performance have been extensively studied.

The experimental results indicate that the recovery factor for each cycle is reduced to 40% to 60%,

compared with that of the previous cycle. The recovery factor in each cycle is mainly affected by the total gas

slug size injected and the maximum pressure built up by gas injection. Chasing CO2

with N2

can effectively

reduce the CO2

usage, while increase the reservoir pressure to an ideal level, so that the maximum value of the

amount of the oil as recovered by per unit of CO2

injected can be obtained. It is also found that a long soaking

period is necessary to achieve a favorable performance while a long soaking time may greatly decrease the

average oil production rate of a cycle. In this study, it was observed that the first cycle rather than two cycles

following it was more sensitive to a long soaking time. The results of this study indicate that CO2

huff-n-puff

process has potential to rapidly improve the single-well performance in low-pressure reservoirs.

1. Introduction

Greenhouse gases (GHG) emissions are commonly identified as a major contributor to global warming.

CO2

-based enhance oil recovery (EOR) techniques have shown great potential to recover remaining oil


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in secondary or tertiary production while offset the GHG emissions by means of sequestrating CO2

underground. CO2

flooding and cyclic CO2

injection (CO2

huff n puff), are two widely applied

CO2

-based EOR techniques. The applicability of either EOR techniques mainly depends on reservoir

conditions, reservoir fluids, formation properties, and the availability of CO2

sources.

This study targets at a reservoir located in northwestern China with a very low original pressure of 12.9

MPa, far below its measured MMP value of 23 MPa. In addition, the reservoir formation is very tight,

permeability averaged 2.3 mD, in some regions even as low as 0.978 mD. The original reservoir pressure

is so low that there is no sufficient energy for the reservoir to do primary production. Furthermore,

waterflooding, a popular EOR method across the world, is not an option for this reservoir because of its

quite low permeabilities. The injectivity required by a successful waterflooding is not achievable.

However, for CO2

injection, injectivity problems do not exist. Additionally, there are abundant CO2

sources from large-scale coal chemical plants in the neighborhood of the reservoir and available for CO2

EOR use. Considering that CO2

flooding is not applicable in low-pressure reservoirs because of its poor

performance when an operation pressure is far below the corresponding MMP, CO2

huff-n-puff process

is a rational option.

CO2

huff-n-puff process is a typical single well operation, which was presented as an alternative of

cyclic steam stimulation for enhanced oil recovery (Stright et al., 1977; Patton et al., 1982; Monger-McClure et al., 1991). This process involves the injection of a slug of CO2

, followed by a soaking time

allowing gas phase to mix with oil phase in place. Following the soaking time, the well is put into

production. The efforts to investigate the applicability of this process to enhance oil recovery have been

made for several decades with encouraging results. The results of laboratory tests and field treatments

demonstrated that CO2

huff-n-puff process is economically viable in diverse reservoir conditions.

Khatib et al. (1981) reviewed results of previous cyclic coreflood tests and field applications on

miscible CO2

injection and indicated that the use of CO2

is applicable in both heavy and light crude

to enhance oil recovery. Sayegh and Maini (1984) evaluated a huff-n-puff process in a Lioyminster

heavy oil reservoir by performing corefloods using CO2

and recycled produced gases. They

conducted an evaluation of relative permeabilities to gas and water at reservoir conditions as well as

an assessment of the longitudinal distribution of CO2 and the effect of soak period. On the basis offield-treatment evaluations, Patton et al. (1982) and Haskin and Alston (1989) developed two

correlations to predict the process performance and some criteria to evaluate the extent to which how

a cyclic CO2

injection process is successful. One important economic indicator presented of

successful implementations is CO2

utilization, defined as the volume of CO2

used for per unit volume

of incremental oil produced, in unit of Mscf/STB. Its favorable rang is from 0.5 to 0.8 Mscf/STB.

Monger-McClure and her colleagues developed extensive research works on the feasibility of CO2

huff n puff process on light-oil recovery (Monger-McClure and Coma, 1988;Thomas et al., 1990;

Monger-McClure et al., 1991;Thomas and Monger-McClure, 1991). They investigated the influence

of various critical parameters, including CO2

slug size, the number of cycles, operational pressures,

impurity of CO2

, reservoir gas, and gravity segregation and remaining oil saturation, by conducting

laboratory coreflood tests on watered-out cores in conjunction with comprehensive reviews ofhundreds of field applications. It was suggested that light-oil recovery by CO

2huff-n-puff either in

pressure-depleted reservoirs or for waterflood residual oil is promising. In addition, they also

compared the recovery mechanisms between CO2

injections on light-oil with heavy-oil. Torabi and

his team member investigated the performance of CO2

huff-n-puff process in naturally fractured

reservoirs by conducting experimental and simulation studies (Torabi and Asghari 2010;Torabi et al.

2012). Even though the volume ratio between fracture and matrix used in their laboratory model were

much larger than that in real reservoir scenarios, their research work filled the lack of information

relevant to the application of CO2

huff-n-puff process in naturally fractured reservoirs.

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Numerical simulations by history-matching field

performance revealed that reduction of oil viscosity,

oil swelling, and gas relative permeability hysteresis

are the principal mechanisms contributing to CO2

huff-n-puff response (Hsu and Brugman 1986;De-

noyelle and Lemonnier, 1987).

However, nearly all the available experimental studies mentioned above simulated the displacementprocess for remaining oil after waterflooding in a reservoir with a constant pressure boundary or connected

to an aquifer. There were two commonalities existing among the aforementioned experimental operations.

One was of core preparation: the core used in corefloods was firstly flooded with brine completely to

measure its pore volume and then was flushed with oil sample used in tests till no water was displaced

out to establish the oil saturation and connate water saturation. Afterwards, the core was flooded again till

no oil production was observed to ensure the subsequent oil recovery was really tertiary. The other feature

in common for those tests existed in production phase. Those production phases started with opening

injection end of a core to produce oil while pumping brine back into the core from the other end to

simulate a water flux. So, what they simulated is a physical process of CO2

huff-n-puff occurring in a

reservoir with a constant pressure boundary or connecting to an aquifer. During those processes, reservoir

pressure can be maintained. However, it is common in reality, just as the targeted reservoir in this studythat a reservoir has neither a constant pressure boundary nor an aquifer but a closed boundary and also

lacks of original energy to do primary recovery. For a closed boundary reservoir, it is difficult to maintain

its pressure during production phase, actually a pressure deletion process. The pressure depletion

production process should have some differences in performance form that pressure maintained process

mentioned above. However, few literatures are available on the cyclic CO2

injection in a low-permeability

reservoir with closed outer boundary with a pressure depletion process during production. This study

mainly focuses on the investigation of the performance of CO2

huff-n-puff process in a low-pressure and

low-permeability reservoir with a closed boundary and without an aquifer.

The objective of this study is to investigate the influence of primary operating strategies to maximize

the response of CO2

huff-n-puff in a target reservoir through laboratory coreflooding tests. This study

extends the insight into cyclic CO2

treatment at the primary production stage in a closed boundary tight

oil reservoir. The results suggest that the recovery factor of a three-cycle huff-n-puff gas injection can be

as high as 34.65%. 0.1 PV CO2

slug seems to be the optimum injection slug size for the first cycle

operation with a favorable CO2

utilization as low as 0.324 Mscf/STB. N2

is a good chasing gas that can

significantly improves the economy of the operation.

2. Pressure-Volume-Temperature (PVT) Studies

2.1. Crude oil sample

In this study, cyclic laboratory corefloods were conducted to investigate the performance of CO2

injection

processes in a low-pressure, low-permeability, and light-oil reservoir. A light crude oil from an oilfieldin northwestern China used in the corefloods has an API gravity of 40.34. The oil phase sample was

flashed down to atmospheric conditions to obtain the dead oil and reservoir gas samples. The properties

of the obtained dead oil are listed inTable 1.The average molecular weight of produced gases is 32.125

kg/kmol and its molar fraction in reservoir fluids is 46.95%.

2.2. Recombined live oil properties

The dead oil was combined with produced gases at reservoir conditions to a gas-oil ratio (GOR) of 57.65

m3/m3 and is used in the CO2

coreflooding tests. Other primary pressure-volume-temperature (PVT)

properties of the recombined oil, such as bubble point pressure, density, viscosity, and swelling factor (SF)

Table 1Properties of dead oil

Desity @ 20C 857.9 kg/m3 (33.51API)

Average Molecular Weight 294.92 kg/kmol

C11 Molecular Weight 354.07 kg/kmol

SPE-169235-MS 3


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were also measured at reservoir temperature of

44C and summarized in Table 2. The schematic

experimental setups used in this study are shown in

Figure 1.

2.3. PVT properties for recombined oil-CO2

mixture

To simulate the effects of CO2

injection on the properties of reservoir oil during CO2

huff-n-puff process,

a PVT study was carried out for the equilibrium system of the mixture of recombined oil and CO2

over

the range of CO2

molar fraction from 23.18 to 67.13 mol%. The equilibrium properties of mixture are

listed inTable 3, including bubble point pressure, density, viscosity, and SF. Here, SF is defined as the

volume of CO2-saturated reservoir fluids that is divided by the volume of reservoir fluids.Table 3showsthat the bubble point pressure and the swelling factor of the mixture significantly increase with the molar

fraction of CO2

, whereas the viscosity of oil dramatically decreases with it. Previous literatures suggested

that oil-swelling and viscosity reduction are two principle recovery mechanisms in CO2

injection process.

3. Huff-n-Puff Coreflood Study

In this study, the coreflooding tests were conducted in a 984 mm-long, 25.38 mm-diameter composite core

drilled from the same area as the sampled oil. This core has a reservoir pore volume (PV) of 95.8 mm 3,

an average porosity of 19.6%, and an average permeability of 117 mD. The reservoir pressure is 6.58 MPa

Table 2Recombined oil properties @ 44C

Bubble point pressure Pb

(MPa) 7.45

Density (kg/m3) 823.6

Bo (m3/m3) 1.1458

GOR (m3/m3) 67.2

Viscosity @ Pb

(cP) 2.60

Figure 1Schematic diagram of oil phase behavior measurement apparatus

Table 3Equilibrium liquid properties of CO2

and live oil mixture @ 44C

CO2

molar fraction

(mol%)

Pb

(MPa)

Density @ Pb

(kg/m3)

Viscosity @ Pb

(cP) Swelling factor

23.18 10.75 814.9 1.20 1.0616

37.24 11.95 813.4 0.99 1.140241.18 12.18 805.2 0.82 1.1792

59.96 15.88 803.0 0.63 1.3427

64.65 21.30 792.0 0.50 1.4932

67.13 25.25 785.1 0.42 1.5624

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while reservoir temperature is 44C. The impacts of

primary operational parameters, such as slug size,

the number of cycles, maximum pressure and chas-

ing gas (N2

) on the performance have been investi-

gated. The purity of CO2

used for this study was

99.99% and formation water used was formation water obtained from the same formation as oil sample,

containing 2 wt% CaCl2

and 1.5 wt%MgCl2

, pH value ranging from 3.0 to 4.0. The use of formation water

can minimize the clay swelling during the process.

3.1. Experimental setup

Figure 2shows the schematic diagram of the huff-n-puff coreflooding experimental setup. The core was

placed horizontally in the middle of the core holder which was coated with an isothermal case to maintain

the temperature at a constant value, 44C in this study. The horizontal core eliminated the gravity effect

on production. The injection gas, reservoir water, recombined oil, and washing liquid were contained

separately in cylinders connecting to transform vessels. Those vessels were used together with the

displacement pumps to inject the fluids into the core. A back pressure regulator was used to maintain the

core pressure. The pressures applying to the both ends of the core and the annulus were monitored using

pressure gauges, respectively. The annulus pressure was maintained at a pressure around 2.1 MPa higher

than the core pressure to protect the core against rupture. The produced fluids were introduced into a

three-phase separator at ambient conditions and the production gas was measured by a gas flow meter.

3.2. Experimental procedure

The huff-n-puff coreflooding tests were conducted with the recombined oil at a temperature of 44C. A

composite core was used to simulate the typical reservoir properties. It was prepared by organizing 22

reservoir core plugs drilled from the same formation with different length, porosity, and permeability. The

reservoir properties are listed inTable 4.

In the traditional coreflooding process, fluid is injected from one end of the core and the oil is produced

from the other end. However, the cyclic CO2

displacement uses one end of the core for both gas injection

and oil production to mimic a single-well operation. In this study, the other end of the core was closed

Figure 2Diagram of huff-n-puff coreflood apparatus.

Table 4 Reservoir properties

Permeability

(mD)

Prosodity

(%)

Temperature

(C)

Pressure

(MPa)

117 19.6 44 6.58

SPE-169235-MS 5


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to model a reservoirs closed outer boundary frequently encountered in field cases. The reservoir boundary

condition modeled in this study was different from those by previous literatures (Monger-McClure and

Coma, 1988;Thomas et al., 1990;Monger-McClure et al., 1991;Bardon et al., 1994;Shayegi et al., 1996;

Zhang et al., 2006), where a constant reservoir boundary with an aquifer was involved.

Table 5Conditions of CO2

huff-n-puff corefloods @ 44C (with a pressure drop of 0.5 MPa across the core)

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First, each core was completely saturated with formation water to measure its pore volume. Then, the

recombined oil was pumped into the core till no additional water produced to establish the original oil

saturation and connate water saturation. The core saturated with oil underwent subsequently a process of

aging to re-establish its wettability. All those operations occurred at reservoir conditions (5.68 MPa and

44C). Compared with the huff-n-puff corefloods by other researchers (Monger-McClure and Coma,

1988;Thomas et al., 1990;Monger-McClure et al., 1991;Bardon et al., 1994;Shayegi et al., 1996;Zhang

et al., 2006), the saturated core with oil in this study was not flooded again with formation water since

here CO2

huff-n-puff process was applied at the primary stage of production.

Once oil saturation and connate water saturation were established, the cyclic CO2

displacement process

was initiated by injecting gases from a compressed gas cylinder connected to the core injection end at a

constant injection rate measured at reservoir temperature of 44Cand ambient pressures. When the

designed amount of gases was completely pumped into the core, the gas injection (huff portion) ceased.

The injected gas slug was designed so that the core pressure was built up to a desired level. When chase

gas involved in the corefloods, it was injected after CO2

injection. Upon the cessation of gas injection, the

core was shut in for a period of time (soak period). Then, the core was returned to production (puff

Table 6Summary of CO2

huff-n-puff coreflooding test results

Runs Maximum pressure (Mpa) Recovery factor (%) Ultimate recovery factor (%)

1 11.37 14.28 Test 1 24.16

2 5.35 5.7

3 4.85 3.48

4 4.05 0.7

5 13.96 15.91 Test 2 31.536 9.25 7.49

7 8.64 4.63

8 8.4 2.42

9 7.69 1.08

10 13.48 13.78 Test 3 28.78

11 8.89 7.06

12 8.21 4.59

13 7.89 2.46

14 7.39 0.89

15 13.33 16.17 Test 4 32.9

16 9.04 8.48

17 8.42 4.87

18 8.61 2.21

19 7.51 1.17

20 11.37 9.47 Test 5 24.8

21 11.37 7.06

22 11.37 4.76

23 11.37 11.37

24 11.37 1.13

25 11.37 10.2 Test 6 26.66

26 11.37 7.43

27 11.37 4.78

28 11.37 2.91

29 11.37 1.34

30 8.15 7.7 Test 7 17.33

31 6.88 4.62

32 12.34 5.01

33 11.74 8.32 Test 8 18.80

34 10.86 6.33

35 12.58 4.15

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portion) from the injection end of the core while the other end was being closed. The production stage was

terminated when core pressure depleted to a certain level. The produced fluids were routed to the three

phase separator where oil phase and gas phase were permitted to separate. The produced oil was weighed

and its volume was calculated from the density of the dead oil. Once the volume of produced oil was

gained, the recovery factor for each cycle and the ultimate recovery factor for a whole test were calculated

from the volumetric material balance. The produced gas was routed into a gas meter to be measured there.

Obviously, the production process in this study was a pressure-depletion process, which was also differentfrom other studys operational pressure of a constant value during the production process (Monger-

McClure and Coma, 1988; Thomas et al., 1990; Monger-McClure et al., 1991; Bardon et al., 1994;

Shayegi et al., 1996;Zhang et al., 2006). This injection-soaking-production process described above is one

typical huff-n-puff cycle.

A second cycle of gas injection was carried out immediately after the first cycle oil production ceased

and a third cycle conducted after the second one and so on. The same procedures were repeated in the

subsequent cycles in the similar manner to the first one with an exception that, in some cases, different

slug sizes of gases were injected. Upon the completion of a test, the core was cleaned carefully using the

same procedure described byMonger and Coma (1988)but petroleum ether rather than xylene was used

as cleaning liquid according to relevant Chinese regulations.

During the huff phase, pressure was gradually built up from the original reservoir pressure of 6.58 MPato the expected level while during the puff phase, the core pressure was depleted at a constant depletion

rate, 3- or 1.5 MPa/h, from the maximum pressure to a designed level with a pressure drop of around 0.5

MPa across the core. During soaking time, the slight pressure change of the core was observed which

might result from the dissolution of CO2

into oil phase. To investigate the effects of soaking time, three

different durations of soaking time, 10, 3, and 1 h, were implemented in the study. Eight series of cyclic

coresfloods, 35 runs in total were conducted, 32 runs carried out used pure CO2

as injection gas (runs 1

through 32) while runs 33 through 35 injecting N2

after CO2

injection as chasing gas. Experimental

conditions for this study are concluded in Table 5and oil displacement results are presented inTable 6

andFigures 3 through 11.

4. Result and Discussions

4.1. Recovery factor

To investigate the potential recovery of CO2

cyclic operations for low-pressure light oil reservoirs, 8 series

of multi-cycle corefloods were conducted, the corresponding operation conditions tabulated in Table 5.

Tests 2 through 5, and 6 were five-cycle operations, Test 1 was a four-cycle operation, and Tests 7 and

8 were three-cycle injection processes. Tests 1 through 7 used pure CO2

, while Test 8 injected certain

amount of N2

upon the completion of the injection of 0.1 PV CO2

slug. FromTable 6, it is observed from

the results of Tests 1 through 4, four series of pure CO2

operations with constant slugs injected, that the

process response significantly declined in the subsequent cycles compared with previous cycles. Take

four-cycle operation Test 1 (Runs 14) as an example, the injected pure CO2

slug size in each run was

0.2 PV. The recovery factor of run 2 was 5.7% OOIP, around 40% of that of Run 1, 14.28% OOIP, while

the recovery factor of Run 3 was 3.48% OOIP, 60% of that of Run 2. It is also observed that the recovery

factors of the forth/fifth cycle was negligible when compared to the first three cycles and the oil

production was mainly from the first three cycles. For example, the sum of the recovery factors of the last

two cycles of Test 2, a five-cycle operation with a CO2

slug of 0.3 PV for each of its cycle injections, was

less than 13% of the total oil recovery of the first three cycles. This decline trend of oil recovery in the

cyclic gas injection sequence is consistent with the observations reported in the low-permeability

corefloods (Wang et al., 2013). The variation trend of recovery factor in sequential cycle operations

suggests that an economical cyclic CO2

injection should consist of three cycles.

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The total recovery factor of the first three cycles of Tests 1 through 8 achieved in this study rangedfrom 17.33% OOIP for Test 7 to as high as 29.52% OOIP for Test 4 and was observed to be sensitive to

the operation conditions, such as CO2

injection rate, gas slug size, maximum operation pressure, and

soaking time. The CO2

huff-n-puff technique is viable to recover the oil in low-pressure light oil reservoirs

with closed outer boundary.

4.2. Effects of the CO2

injection rate

The injection rate is one of the important operation parameters for CO2

huff-n-puff field applications. In

field operations of CO2

huff-n-puff process, CO2

is usually recommended to be injected at the highest rate

that the formations can hold, helping the gas phase penetrate as far into the rock and contact as much oil

as it can (Karim et al., 1992,Liu et al., 2005). In this study, to address the effects of the injection rate on

light-oil CO2

huff-n-puff process, two analogous five-cycle operations, test 5 (runs 20 through 24) and test

6 (runs 25 through 29), were performed under the same operation conditions except using two different

injection rates, 480 cc/h for test 5 and 720cc/h for teat 6. The test results were concluded in Table 6and

also compared inFigure 3. The bar charts inFigure 3show that the CO2

injection rate of 480cc/h, when

compared to the injection rate of 720 cc/h, is able to generate more favorable performance either for one

single cycle or one complete test. The improvement of the performance for the first two cycles is more

noticeable than other cycles. It seems that a smaller CO2

injection rate, such as 480 vs. 720cc/h, may lead

to a more successful CO2

cyclic operation. This trend is contrary to the observations seen in another

low-permeability corefloods (Wang et al, 2013) with the same boundary conditions as this study. In the

low-permeability corefloods, two CO2

injection rates of 60 and 140cc/hr were examined and it was found

that the injection rate of 140cc/h produced some performance improvement. On the basis of the

combination of the observations in those two coreflood, the optimal CO2

injection rate for a CO2

huff-n-puff application with a closed outer boundary should lie between 140- to 480cc/hr. Further

corefloods using intermediate injection rates are needed to identify its optimal vale. Neither a large

injection rate, such as 720cc/hr, nor a small one, such as 60cc/h can benefit the cyclic CO2

injection

processes. This observation is similar to that presented by Karim et al. (1992). In their study, the

injection rates of 60, 100, 140, 160, and 200 cc/h in first- and second-cycle operations of cyclic CO2

injection process were conducted using a watered-out conventional core. They observed that the

intermediate injection rate of 140 cc/hr was the optimal injection rate to maximize the overall process

performance. The observation differences between this study and Karim et al. may mainly lie in the

differences in simulated reservoir boundaries.

Figure 3RF comparison between Test 5 with an injection rate of 720cc/h and Test 6 with an injection rate of 480 cc/h.

SPE-169235-MS 9


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4.3. Effects of CO2

slug size

CO2

slug size is a primary factor for an economi-

cally successful CO2

huff-n-puff process. To inves-

tigate the effects of the CO2

slug size on the oper-

ation response and optimize it, three series of

corefloods, Tests 1, 3, and 7, were conducted using

CO2 slugs ranging from 0.1 PV to 0.3 PV. Test 1was a four-cycle operation, Runs 1 through 4, each

Run using constant CO2

slug size of 0.2 PV. Test 2

was a five-cycle operation using constant CO2

slug

size of 0.3 PV in each cycle while Test 7 used 0.1,

0.2, and 0.3 PV slug sequentially in its three cycles.

Test results were concluded inTable 6. Comparing

the performance of Runs 1, 5, and 30, the first-cycle

operations of Tests 1, 2, and 7, respectively, shows

that Run 5, achieving a recovery factor of 15.91%

OOIP, was more favorable than Run 1, 14.28%

OOIP, and Run 1 was more favorable than Run 30,7.7% OOIP. It is suggested that injecting a large

CO2

slug in the first cycle benefits the cycle per-

formance a lot. The same trend can be seen for the

subsequent cycles as well.

Comparing the total oil recovery and the corre-

sponding CO2

consumption for the first three cycles

between Tests 1 and 7, 23.46% OOIP and 0.6 PV

vs. 17.33% OOIP and 0.7 PV, shows that Test 1

using a constant CO2

slug of 0.2 PV in each of its

cycles was more favorable and economic than Test

7, using sequentially doubled CO2

slugs for its three

cycles. It is suggested that, compared to injecting

increasing CO2

slugs in the subsequent sequences,

using a constant CO2

slug in each cycle operation is

an ideal operation scheme.

To analyze the CO2

efficiency of the operations

of Tests 1, 2, and 7, the average cycle performance

with respect to 0.1 PV CO2

slug, is calculated and the comparison of it is done among those three tests,

as shown inFigure 4.Figure 4displays that Run 30 was most favorable when compared to Runs 1 and

5 and Run 1 is more efficient than Run 5 in terms of the average cycle response corresponding to 0.1 PV

CO2

slug injected. It implies that increasing the CO2

slug in the first cycle operation does not improve the

CO2

efficiency of the operations, a key economic indicator meaning a successful operation.

It can be concluded that injecting a large CO2

slug increases the oil recovery of a cycle operation while

decreases its CO2

efficiency and that injecting a fixed CO2

slug in each cycle of a multi-cycle operation

is an ideal operation strategy to improve its total economy.

4.4. Effects of the maximum pressures

Just as literatures reported, the process response increases with the maximum pressure because a certain

level of pressure support is essential for sustaining production during puff portion (Monger-McClure and

Coma, 1988;Mohammed-Singh et al., 2006,Wang et al., 2013). In addition, High level pressure is the

Figure 4Cycle recovery factor for 0.1 PVs CO2

injection for Tests 1,

2 and 7.

Figure 5The dependence of the recovery factor on the maximum

pressure of the core Run 30 vs. 33.

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primary energy to displace the oil in place for the

pressure-depleted production processes studied in

this paper.

To examine the effects of the maximum pres-

sures on process response, the performance compar-

ison between Runs 30 and 33 were conducted. Both

Runs were first-cycle operations with similar oper-ation conditions, listed inFigure 6, except that Run

33 using 0.1 PV N2

slug following the injection of

0.1 PV CO2

slug. The injection of 0.1 PV N2

slug

after 0.1 PV CO2

slug in Run 33 helped to build up

the maximum pressure to 11.71 MPa, much higher

than that of Run 30, 8.15 MPa. Correspondingly, the

response of Run 33, 8.32% OOIP, is more favorable

than that of Run 30, 7.7% OOIP. The dependence of

the process response on the maximum pressure is

plotted in Figure 5, suggesting that the higher the

maximum pressure of the core is, the more favor-able the process is. The same trend can be seen from

the performance of Runs 1 vs. 5 and 31 vs. 34. The

level of the maximum pressure should be as high as

the rock can hold.

Figure 6 displays how the oil production rates

varied with the core pressure for Runs 30 and 33,

respectively, over the whole puff portion the core

pressure depleted from the maximum pressure to the

termination pressure of 3 MPa. It is suggested that

building up the maximum pressure to a high level is

helpful to extend the production duration with re-

spect to the fixed termination pressure, e.g. 3 MPa

for Runs 30 and 33, and the oil production rates are

generally much larger at the early production stage,

the core pressure depleted from the maximum value

to a certain level, e.g. around 6 MPa in this study, than at the later production stage, pressure depleted from

6 MPa to the termination pressure. Therefore, the performance in the early production stage is more

favorable than in the later production stage. It can be confirmed by analyzing the contribution of different

production stages to the oil production of a Run. Take Run 33 as an example, building up the maximum

pressure of 11.74 MPa by injecting 0.1 PV CO2

slug plus 0.1 PV N2

and terminated at the pressure of 3

MPa. So, the pressure drop of Run 33s puff portion was 8.74 MPa. The first production stage of it

consumed less than two-thirds of the whole pressure drop but produced nearly 85% of its oil production.

It indicates that for the pressure depleted production processes, the early production stage with higher

level pressures is the major contributor to the oil production, more favorable and efficient than the later

stage when the pressure significantly depleted to a certain level.

4.5. Effects of chasing gas

As mentioned above, the high level of maximum pressure caused by gases injection improves the recovery

significantly. The high maximum pressure may be achieved by injecting a large CO2

slug or injecting a small

CO2

slug plus an additional chasing gas slug, such as N2. However, just asFigure 4displayed, the increasing

Figure 6Effects of the maximum pressure on oil production process

for Run 30 vs. Run 33.

Figure 7Comparison of CO2

efficiency between Tests 7 and 8.

SPE-169235-MS 11


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CO2

slug would decrease the CO2

efficiency and

therefore lower the economy of operations. It was

proven that injecting N2

following a CO2

slug has

greatly potential to improve the process response of

CO2-based EOR processes (Rowe et al., 1982;Karim

et al., 1992;Shayegi et al., 1996). In this study, the

viability of using N2 as chasing gas for CO2-basedclose-boundary cyclic gas injections was investigated

by conducting a tree-cycle operation of Test 8.

The three cycles of Test 8, Runs 33 through 35,

sequentially injected 0.1 PV CO2

slug plus 0.1 PVs N2

slug, 0.1 PV CO2

slug plus 0.2 PV N2

slug, and 0.1 PV

CO2

slug plus 0.3 PV N2

slug. The maximum pressure

achieved in Run 33, the first cycle of Test 8, was 11.74

MPa, larger than 11.37 MPa, the maximum pressure

caused by 0.2 PV pure CO2

slug in the first cycle

operations. The maximum pressures built up in the

second cycle of Test 8, Run 34, was 10.86 MPa, largerthan that caused by 0.3 PV CO

2injected in the second-

cycle operations, 9.04 MPa, and the Run 35s maxi-

mum pressure reached the same level of that caused by

injection 0.4 PV CO2

slug in Run 32, the third cycle

operation of Test 7. It is suggested that with respect to

a desirable level of maximum pressure, injecting N2

after the injection of a small slug of CO2

dramatically

reduce the usage of CO2

and therefore improve the

CO2

efficiency of operations.

To evaluate the effects of injecting N2

immedi-

ately after the injection of CO2

on the CO2

effi-

ciency of processes, the comparison between Tests

7 and 8, pure CO2

injection vs. CO2

plus N2

injec-

tion with the similar conditions, was conducted by considering the average cycle response caused by 0.1

PV CO2

slug and was displayed in Figure 7. It was suggested that using N2

as chasing gas had great

potential to improve the CO2

efficiency of operations and this improvement was more significant in

subsequent cycles when compared to the previous ones.

4.6. Effects of the pressure depletion rate

To address the effects of pressure depletion rate on light oils huff-n-puff processes, two pressure

depletion rates, 3- and 1.5 MPa/h, were examined. 3 MPa/h was used for Tests 1 through 3, 5, and 6, and

1.5 MPa/h for Tests 4, 7, and 8. Among those 8 Tests, Tests 2 and 4 were analogous except using different

pressure depletion rates and were compared from two aspects of the cycle response: cycle recovery factor

and the average oil production rate of the cycle, illustrated inFigures 8and9, respectively. FromFigure

8,it is seen clearly that the recovery factor of each cycle of Test 4, using the pressure depletion rate of

1.5 MPa/h, is more favorable than that of the same cycle of Test 2, using the pressure depletion rate of

3 MPa, while the improvement resulted from the decrease of pressure depletion rates is negligible.

Inversely, Figure 9 shows that the pressure depletion rate of 3 MPa/h for Test 2 induced some tiny

improvements of the cycles average oil production rate when compared to the pressure depletion rate of

1.5 MPa/h for Test 4.

Figure 8Effects of the pressure depletion rates on the cycle recovery

factor

Figure 9Effects of the pressure depletion rate on the cycles average

oil production rates for Tests 2 and 4

12 SPE-169235-MS


13/16

Based on the test results in this study, it is sug-

gested that using different pressure depletion rates

may affect the process response positively or nega-

tively, but the resulted effects were unmeasurable.

4.7. Effects of soaking time

Soaking time is a major consideration when de-

signing a CO2

huff-n-puff process. To investigate

its effects on the process response and figure out

the optimal soaking period of the cyclic CO2

in-

jections in low-pressure light oil reservoirs with

closed outer boundary, Tests 2 and 3 were con-

ducted under similar conditions with an exception

of allowing different soaking periods. Long soak-

ing periods were used in the successive cycles of

Test 2 (10-h soak time for the first cycle, Run 5, vs.

3-h soaking time for the remaining four cycles,

Runs 6 through 9.) to have the core pressure stabi-

lized, while a short soaking time of 1 hour was used

in each cycle of Test 3, Runs 10 through 14.

The results of those two Tests (listed in Table 6)

indicated that, for the first cycle, the oil recovery was

significantly increased by 15.5 % when the soaking

time was extended from 1 hour for Run 10 with a

recovery factor of 13.78% OOIP to 10 hours for Run

5 with a recovery factor of 15.91% OOIP. However, if

compared to Run 5 in terms of the average oil pro-

duction rate, as plotted inFigure 10,the performance

of Run 10 was much favorable than that of Run 5. Run10 achieved an average oil production rate of

14.14108 BOPD, nearly as twice as that of Run 5,

7.9108BOPD. It suggested that an over-extended

soaking time may greatly reduce the average oil production rate of the cycle operations.

For the second-cycle operations, as plotted inFigure 11, Run 6, allowing 3 hours soaking, exhibited

the slight improvement in oil recovery, 7.49% OOIP vs. 7.06% OOIP for Run 11, using 1 hour soaking,

but the measurable decrease in the average oil production rate, 7.1108 vs. 8.75108 BOPD for Run

11. The same observations can be obtained for the third-cycle operations, Runs 7 vs. 12.

It is indicated that a long soaking period, such as 10 hours in this study, helped a lot to improve the oil

recovery in the first cycle but simultaneously significantly decreased the average oil production rate of the

process. However, for the second- and third-cycle injections, allowing 3 hours vs. 1 hour to shut in did not showa noticeable improvement in oil recovery while resulted in unfavorable average oil production rate. Different

from the observations ofWang et al. (2013), for low-pressure light oil CO2

huff-n-puff injections, the first cycle

rather than the second and third cycles was more sensitive to a long soaking time.

5 Conclusions

Based on the results of this study, some conclusions can be summarized as follows:

1. The CO2

huff-n-puff technique is viable to enhace oil recovery in low-pressure tight oil reservoirs

with a closed outer boundary.

Figure 10The performance comparison between Run 5 with 10 h

soaking time and Run 10 with 1 h soaking

Figure 11The performance comparison between Run 6 with 3 h

soaking time and Run 11 with 1 h soaking

SPE-169235-MS 13


14/16

2. The economically optimum huff-n-puff gas injection consists of three cycles with a potential

recovery factor of as high as 29.52% OOIP.

3. For the first cycle, a small CO2

slug size showed an attractive result. 0.1 PV CO2

plus a proper

amount of N2

as the chasing gas to build up the reservoir pressure seems to be the best injection

strategy in terms of the recovery factor and CO2

efficiency. Using more CO2

sequential cycles is

more favorable than than using large CO2

slug sizes.

4. The injection of N2after a CO2slug can dramatically reduce the usage of CO2. The performancestrongly depends on the maximum pressure built up during the gas injection period. It is

recommended that the injection pressure of CO2

huff-n-puff is better to be built up to as high as

rock permits.

5. High injection rates of CO2

is unfavorable for the oil production.

6. A soaking time is required in cyclic CO2

injection process with closed boundary to achieve

favorable recovery efficiency while a long soaking time may greatly decrease the average oil

production rate of a cycle. In this study, it was observed that the first cycle rather than two cycles

following it was more sensitive to a long soaking time.

7. The influence of pressure depletion rates were marginally to the performance of CO2

huff-n-puff.

AcknowledgementsThe authors would like to acknowledge the permission for the pubilication of this paper from Yanchang

Petroleum (Group), China.

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16 SPE-169235-MS

experimental study of co2 huff-n-puff process for low-pressure reservoirs

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