Gas injection assisted steam huff-n-puff process for oil recovery from deep heavy oil reservoirs with low-permeability

Gas injection assisted steam huff-n-puff process for oil recovery from deep heavy oil reservoirs with low-permeability

Journal Pre-proof Gas injection assisted steam huff-n-puff process for oil recovery from deep heavy oil reservoirs with low-permeability Tao Wan, Xiao...

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Journal Pre-proof Gas injection assisted steam huff-n-puff process for oil recovery from deep heavy oil reservoirs with low-permeability Tao Wan, XiaoJun Wang, Ziyan Jing, Yang Gao PII:

S0920-4105(19)31034-4

DOI:

https://doi.org/10.1016/j.petrol.2019.106613

Reference:

PETROL 106613

To appear in:

Journal of Petroleum Science and Engineering

Received Date: 6 June 2019 Revised Date:

29 September 2019

Accepted Date: 22 October 2019

Please cite this article as: Wan, T., Wang, X., Jing, Z., Gao, Y., Gas injection assisted steam huff-npuff process for oil recovery from deep heavy oil reservoirs with low-permeability, Journal of Petroleum Science and Engineering (2019), doi: https://doi.org/10.1016/j.petrol.2019.106613. This is a PDF file of an article that has undergone enhancements after acceptance, such as the addition of a cover page and metadata, and formatting for readability, but it is not yet the definitive version of record. This version will undergo additional copyediting, typesetting and review before it is published in its final form, but we are providing this version to give early visibility of the article. Please note that, during the production process, errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain. © 2019 Published by Elsevier B.V.

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Gas injection assisted steam huff-n-puff process for oil recovery from deep heavy oil reservoirs with low-permeability

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Tao Wan1, XiaoJun Wang2, Ziyan, Jing3, Yang Gao2

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1 Faculty of Petroleum, China University of Petroleum (Beijing) at Karamay, China

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2 Research Institute of Exploration and Development, Xinjiang Oilfield Company, PetroChina

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3 Research Institute of Petroleum Exploration & Development-northwest (NWGI), Petrochina

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Tel:0990-6633531 Fax: 0990 6633510 Email: [email protected]

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Abstract

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The primary objective of this paper is to evaluate the possibility of using gas assisted cyclic steam stimulation for

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enhanced oil recovery in Xinjiang low-permeability heavy oil reservoirs. Several attempts have been made in this

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paper to improve the recovery efficiency, which include hydraulic fracturing horizontal wells, flue-gas and CO2

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assisted cyclic steam co-injection, alternating injection of steam and CO2 scheme.

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To reduce the heavy oil viscosity and heat losses, cyclic flue-gas/steam injection method was proposed to make the

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gas penetrate deep into the formation and expand the steam chamber. Numerical simulations were carried out to

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examine the thermal process recovery efficiency of gas assisted steam injection in producing low-permeability

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heavy oil.

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The numerical results indicated that gaseous additives such as CO2 or flue-gas were feasible to improve the

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performance of cyclic steam injection. Without a gas blanket filling the chamber, the heat losses would become

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significant. Our research results indicated that the CO2/steam coinjection yielded higher oil recovery than flue-

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gas/steam and pure cyclic steam injection process. The thermal recovery performance is largely dependent on the

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contacted area of the steam with the oil reservoir. One reason is that the cumulative injected enthalpy of the

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CO2/steam is higher than flue-gas/steam and pure steam. Another reason is that the addition of nitrogen or carbon

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dioxide acts a role as thermal isolation to reduce the heat losses along the wellbore due to their low conductivity.

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The interaction of CO2 injection with reservoir heavy oil under temperature effect was discussed. Compared with the

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case without considering the temperature effect, the oil rate and cumulative oil recovery was higher for the case

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including the temperature dependent relative permeability.

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Keywords

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Flue-gas assisted steam injection; Huff-n-puff; Low-permeability reservoirs; Heavy-oil;

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1. Introduction

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The viscosities of Xinjiang dead heavy oil range from 600-15500 cp at depths of 100-3500 meters, measured at

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temperatures of 50 oC. The discovered heavy oil reserves are buried in low permeability formations. It remains a

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great challenge to recover oil from the low permeability reservoirs, not to mention heavy oil plays. Oil mobilization

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is impossible in this case without introducing thermal energy and conductive hydraulic fractures. In emerging heavy

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oil plays, production is greatly constrained by the reservoir permeability. In developing the unconventional

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reservoirs, a practicing strategy is to target the "sweet spots" that have the highest permeability, oil saturation and

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TOC. The well deliverability substantially comes from those sweet spot regions. In terms of heavy oil reservoir

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characterizations, experiences showed that there might be significant variations in pay zone thickness, permeability,

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clay content, thermal maturity and oil saturation. In an attempt to develop the low permeability heavy oil resources,

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the multistage hydraulic fracturing horizontal well in conjunction with CO2 assisted cyclic steam injection technique

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was employed in order to achieve profitable returns. In addition, the well was placed in the play's sweet spot.

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1.1 Gas assisted steam injection process

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Some attempts have been made to examine the influence of adding CO2 and N2 assisted cyclic steam stimulation

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(CSS) process. The current practices for improving the performance of steam stimulation include solvents, CO2, N2

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or flue gas coinjection as thermal supplementation (Zhang et al., 2000; Sedaee and Rashidi, 2004; Canbolat et al.,

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2004; Sharma and Gates, 2010). Field tests and laboratory experiments of the steam-CO2 injection process showed

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improved oil production over cyclic steam stimulation (Clampitt et al., 1991; Canbolat et al., 2004; Naderi and

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Babadagli, 2014). To make it economically viable in producing heavy oil reservoirs, the primary consideration is

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how to reduce the heavy oil viscosity. Combination of CO2 with steam injection is an efficient manner in reducing

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the oil viscosity and swelling of heavy oil. The lab tests demonstrated that the heavy oil viscosity was reduced by 80%

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with CO2 assisted steam injection compared to steam alone (Guo et al., 2018).

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Recent advances in tertiary CO2 core flooding an ultra-heavy crude oil with viscosity about 1665 cp at 50 °C showed

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an incremental of 22% oil recovery even after waterflooding (Seyyedsar et al., 2016). It was observed that CO2

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breakthrough occurred in an early period, but continuous CO2 injection after breakthrough still recovered additional

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oil. Nevertheless, this phenomena is not likely to reproduce in the field. Once CO2 channels through high

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permeability layers to the producer, the incremental oil recovery is negligible and leaving much of the oil unswept.

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Zare and Hamouda (2019) conducted an experimental study on the effect of combing solvents (C6, C7 and CO2)

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aided with steam injection in SAGD process. The experimental results showed an increase in oil recovery by

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solvents coinjection compared to steam injection. During the experimental process, an increase of oil mobility was

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essentially captured due to CO2 swelling of the heavy oil. Li et al. (2017) presented experimental results of

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surfactant aided CO2 huff-n-puff injection in heavy oil rocks. It was demonstrated that surfactant assisted CO2

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achieved 13% higher oil recovery than CO2 huff-n-puff. The primary reason for improved oil recovery could be

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attributed to the foam generated in the process which prevents CO2 channeling via high permeability formations.

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Another noticed point is the synergistic effect of surfactant with CO2 forming an emulsion phase. The mobility of

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emulsified heavy oil was remarkably increased. The viscosity of emulsified heavy oil was only 5% of its original

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value. Additional evidence also suggested that CO2 foam is an effective method for improved heavy oil recovery (Li

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et al., 2011; Hou et al., 2012). The gelled polymer solution was injected to block CO2 channeling and improve the

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vertical steam injection profile.

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1.2 Solvents as additive in steam injection process

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Shu and Hartman (1988) examined the role of solvent as additive in steam processes by numerical experiments. The

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results found that coinjection light solvent with steam caused an adverse effect on steam stimulation performance

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because the injected light solvent increased the gas saturation and resulted in an earlier breakthrough. However,

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medium weight solvents injection achieved a better performance than that of the light solvent (Butler and Mokrys,

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1993; Zhao, 2007). Once the medium solvents make multiple contacts with the heavy oil, a low viscosity oil bank

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successively forms through condensation of the intermediate solvents into oil. The viscosity transition zone plays a

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key role in suppressing the gas fingering. The incremental oil recovery by medium solvents injection is higher than

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light solvents. Some studies made consistent observations on the impact of light solvents (Ito et al., 2001; Liu et al.,

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2012).

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The injection of light gas has an adverse effect on steam chamber propagation because of gas accumulation at the

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front of the chamber. Coinjection of solvent with steam/hot water (Vapex) in horizontal wells was considered as an

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effective thermal recovery method for producing heavy oil reservoirs in Canada (James et al., 2008; Cuthiell 2013;

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Pourabdollah and Mokhtari 2013). The advantage of Vapex process appears where the overburden and underlying

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heat loss is extensive, for example, in deep formations. Since the latent heat of vaporization of hydrocarbon solvent

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is less than water, the heat required is less for solvent to convert a unit mass of a liquid into vapor without change

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temperature. Suppose using pure steam injection in deep formations, the heat loss from surface to the perforated

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zone is significant. It is helpful to fill the annulus of the wellbore with non-condensing gas such as CO2 to lower the

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rate of heat loss to the surrounding formation.

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1.3 Recovery Mechanisms of gas assisted steam injection

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The major challenge for cyclic steam stimulation is the thermal losses to the surrounding rocks and concomitant

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poor production performance. Because the thermal transfer rate (loss rate) for CO2 is much less than steam, it is

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favorable for CO2 to penetrate deep into the formation and expand the steam chamber. The role of carbon dioxide or

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nitrogen in cyclic steam injection process acts as a blanket of heat insulation in that the thermal conductivity of

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nitrogen is much lower than the steam (Atkinson et al., 1980; Moussa et al., 2018). Generating a high quality steam

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in the reservoir is critical for contacting more heavy oil. The flow resistance of steam or CO2 is much less than the

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condensate water (Weaver et al., 1992; Siddique et al., 1993).

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Researchers have reported on using flue gas combined with steam injection to recover viscous heavy oil (Srivastava

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et al., 1999; Montes et al., 2010; Trevisan et al., 2013; Li et al., 2017). The experimental results from peers indicated

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that flue gas with steam recovered more oil than pure steam injection. Flue gas extracts the medium components of

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hydrocarbon from the heavy oil, which results in increased molecular weight of the remaining heavy component.

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The oil recovery factor by flue gas and n-hexane assisted steam flooding was superior to other methods (Li et al.,

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2017). It was claimed that CO2 floods in heavy oil showed better performance than flue gas flooding in that the

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solubility of CO2 into oil was higher than flue gas. It appears that heavy oil production rate is considerably

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dependent on the oil viscosity reduction and oil swelling mechanisms (Paracha, 1985; Srivastava et al., 1999).

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The literature review suggest that our current understanding of the mechanism of cyclic steam injection process in

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low permeability heavy oil reservoirs is inadequacy. In an effort to study the cyclic steam injection projects, a

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fundamental issue is to describe the propagation front of the steam chamber and heat transfer process (Butler, 1985;

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Reis, 1992; Akin, 2005). Various attempts have been made to increase our understanding on steam chamber growth

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and thermal transfer mechanism (Zargar et al., 2018; Liu et al., 2018; Huang et al., 2019). The evolution of steam

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chamber is strongly dependent on the heat loss to the surrounding rocks. If CO2 moves at the front of chamber, it

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lowers the rate of heat loss to the contacted formations. Without a gas blanket filling the chamber, the heat losses

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would become significant in that the steam condensing to water substantially reduce its latent heat.

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1.4 Effect of Temperature dependent relative-permeability

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It should be noticed that the temperature effect on the relative-permeability and its implication on the numerical

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simulation results of cyclic steam injection performance (Serhat et al., 1999; Doranehgard et al., 2017; Esmaeili et

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al., 2019). As external steam or thermal carrier injection into the reservoirs, the mobility of heavy oil would be

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considerably improved by the increased temperature. In order to model the thermal recovery process by CO2 assisted

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steam injection, the changes of relative permeabilities caused by temperature effect has to be considered. By history-

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matching the production data using pressure transient test, it was found that the endpoint of relative permeability to

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oil, also called residual oil saturation, reduced with increasing temperature. It was reported that the viscosity ratio is

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a major factor that affect the steady-state relative permeability of oil (Closmann and Smith, 1983; Polikar et al.,

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1990). The relative permeability is critical to reservoir modeling in that the residual oil saturation endpoint, steam

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injectivity and CO2 production was affected by relative permeability. In this paper, the effect of temperature

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dependent relative permeabilities was included in simulation of thermal recovery heavy oil process. The field trial

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showed that co-injection of steam with CO2 and N2 yields higher cumulative oil recovery than injecting steam alone

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(Hornbrook et al., 1991; Oudinot et al., 2011; Zheng et al., 2013). Current inadequacy in study of the role of CO2

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assisted steam injection in low permeability formations energizes the research of this paper. However, the

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optimization of production and injection length in each cycle was not discussed in this paper.

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1.5 Problem statement and statement of research objectives

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The most prolific by far for known heavy oil is trapped in high permeability formations. The newly discovered

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heavy oil reserves has increased significantly but in-low permeability formations in Xinjiang, China. Owing to the

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low permeability of heavy oil reservoirs, there are some technical difficulties in how to develop these reservoirs

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commercially. Our current understanding of the cyclic steam injection process in low permeability heavy oil

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reservoir is inadequacy. We have examined the relevant parameters in detail that affect the performance of cyclic

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flue-gas, CO2/steam injection process in hydraulically fractured heavy oil reservoirs. The research content of this

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1

paper will provide useful information on exploiting the potential to increase oil recovery from the low-permeability

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heavy oil reservoirs.

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The objective of this paper is to discuss the performance of using flue gas assisted cyclic steam injection in fractured

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low permeability heavy oil reservoirs. With initially heavy oil in place estimated 2600 million barrels in Xinjiang,

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large percentages of the reserve is in low permeability formations. The techniques for producing low-permeability

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heavy oil reservoirs is in great demand. Although years of research have been devoted to developing the low

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permeability heavy oil reservoirs, the current technique is unsatisfactory. According to the data analysis of the

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discovered heavy oil basins, typical reservoir permeability ranges from 57-2566 mD (Meyer et al., 2007). With

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declining supply from the conventional oil resources, the low-permeability heavy oil reservoirs is of interest to the

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oil industry. In order to increase the oil supplies domestically, heavy oils in low-permeability formations are

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emerging in importance.

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2. Simulation model description and Methods

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Table 1 presented the core data such as porosities, permeabilities, and saturations from the coring wells. It

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demonstrated that the newly discovered heavy oil was buried in low-permeability formations. The target reservoir

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burial depth ranges from 1500-2300m. The viscosity of heavy stock tank oil measured at 50 ℃ ranges from 12000-

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26778 cp. The in-situ oil viscosity varies from 150-526 cp. The reservoir porosity and permeability were presented

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in Table 1, acquired from the coring data. The reservoir rock and fluid properties of the targeted formation was

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summarized in Table 2 and 3. The basic thermal parameters used in the wellbore heat loss calculation process was

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presented in Table 4. The fundamental data required in the thermal recovery calculation process was presented in a

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table format.

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Heavy oil mobilization in low-permeability formations without conductive flow paths is very difficult. The

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schematic well structure of cyclic steam injection process used in Xinjiang field was shown in Fig.1. Fig.2 shows the

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coring samples from the heavy oil formations, which is poorly consolidated. The picture of low permeability core

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plugs was not available. The petrophysical measurements of the core rocks showed that the reservoir heterogeneity

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is strong. Fig.3 illustrates the development strategy in low-permeability heavy oil reservoirs-horizontal well drilling

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with hydraulic fracturing treatment. Firstly, the low-permeability horizontal wells was implemented with hydraulic

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fracturing treatments to create more contact volume with the formation. Then, steam coinjection with CO2 in a huff-

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n-puff manner was used to recover the heavy oil. The high-pressure steam with thermal energy not only makes the

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oil more mobile, but also increases the reservoir pressure at the mean time. The injected steam and CO2 will

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preferentially flow through the hydraulic fractures. It has the potential to create as many vapor-chambers as the

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number of hydraulic fractures (as shown in Fig.3). In the production stages, the lowered viscosity of crude oil would

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flow essentially via fractures to the wellbore.

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The input component properties of the heavy oil parameters was presented in Table 5. The K-value is zero for the

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heavy oleic component. It suggests that all of the composition of heavy oil component is liquid phase. The critical

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pressure and temperature of the heavy oil component was defaulted to zero, which represents that the enthalpy is

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independent of the gaseous properties. The enthalpy of heavy oil should be calculated from the Lee-Kesler method.

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A dead oil component will have zero K value.

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The rock and fluid properties used in the thermal simulation model was measured in laboratory from Xinjiang heavy

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oil field located at Karamay, as shown in Table-6. The viscosity of heavy oil and gas phase versus temperature was

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measured as shown in Table-7. The equation of state requires the input of critical properties. The components

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making up the reservoir fluids are lumped into four types: dead oil, solvent gas, flue-gas and steam. The flue-gas and

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steam are treated as separate components because we want to examine their role in the thermal recovery process.

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The number of components in the fluid model has significant effect on computational efficiency. The heavy oil

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model is usually lumped into simple pseudo components of dead oil and solvent gas. This characterization meets

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adequately the needs of modeling heavy oil thermal recovery process with minimum computational cost.

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The thermodynamic flash calculation of the vapor and liquid phases can be implemented as following procedures:

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1

Thermodynamic phase equilibrium of the minimum Gibb’s energy: Gi = ln Ki + ln f iL − ln f iV = 0 Where the fugacities are functions of temperature, pressure and composition: f i = f i (T , p, xi )

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Nc

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i=1,...,N c

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Material balance of the component gives:

( Ki − 1) zi

∑1+ F ( K i =1

v

i − 1)

= 0 , where Ki = xiV / xiL

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The mole fraction of each component in the liquid and gas phases are described by:

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xiL = zi / 1 + Fv ( Ki − 1) , xVi = Ki zi / 1 + Fv ( Ki − 1)

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In this paper, the new generation STARS-CMG reservoir simulator was used for steam injection process. STARS

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was developed for simulating steam flood, steam cycling, steam with additives and many types of thermal

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applications. In the simulation model, the following assumptions had been made to in order to model the thermal

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recovery process:

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(1) In the process of calculating the heat losses in the wellbore, the heat transfer between the fluids and the

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formation interface is assumed to be quasi-steady. (2) The thermal conductivity of the reservoir rock is assumed to be uniform, 1.2×105 J/m-day-K. In other words, the heterogeneity of reservoir has not been taken into consideration during the heat transfer calculation process. (3) The thermal conductivity of overburden and underburden in calculating the heat loss were assumed to be 1.05×105 J/m-day-K. (4) In the fluid model, the reservoir fluids were lumped into three components, water、oil、gas to represent the reservoir compositions.

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Lawal (2011) showed that alternating injection of steam and CO2 was slightly more effective than steam and flue-

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gas co-injection. Due to the high cost of utilizing CO2 and the availability of CO2 source, it is preferred to use flue

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gas as additive to steam injection in this project. However, it is interesting to compare the effect of CO2 and flue gas

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on the performance of cyclic steam stimulation in low permeability heavy oil reservoirs. The 3D reservoir

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simulation model of multistage hydraulic fractured horizontal well was shown in Fig.4 (I-J top view). The horizontal

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well lateral length is 1500 meters with 10 stages of hydraulic fractures. In other words, the spacing of hydraulic

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fracture is 150 meters. Each of the hydraulic fractures was discretized logarithmically with fine grid cells. The

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gridding model ensures that it fully captures the temperature and pressure changes during thermal recovery process.

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The reservoir matrix permeability of the base model is 1-mD. In the succeeding simulation cases, only one stage

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hydraulic fracture controlled volume was modeled because it is computationally intensive using large number of

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grid cells. One-tenth of the fractured well pattern was represented in the simulation model. As a result, the output of

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forecasting production data represents the oil recovery from one stage hydraulic fracture. The implication was that

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the fracture length, fracture stimulated volume and fracture conductivity were the same for all fractures. In the base

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cyclic steam injection case, flue-gas assisted with steam was injected for a period of 200 days. Then the well

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switched to production for 200 days.

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In this paper, the predominant factors such as matrix permeability, injected stream composition and injection

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method has been investigated as presented in Table-8. The injected stream of flue-gas is consisted by 20% steam, 40%

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CO2 and 40% N2. These components are quantified on the basis of mole fractions. For a mixture having N

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1

components, i = 1, . . . , N, the overall mole fractions are defined by:

2

zi =

ni

=

N

∑n j =1

j

mi / M i N

∑m j =1

j

/Mj

3

where n=moles, m=mass, M=molecular weight, and the sum of zi is 1.

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For example, the injected stream of flue-gas is consisted by 20% steam, 40% CO2 and 40% N2. These values are

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referred as mole fraction. In other words, in a solution of 1 mol injected gas, the mole fraction of steam is 0.2 mol,

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the mole fraction of CO2 is 0.4 mole and 0.4 mole of N2.

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A typical flue gas from coal fired power plant is composed of 10-20% H2O, 10-20% CO2, 60-76 % N2. Its

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composition depends on the type of fuel and the combustion conditions. Unnecessary high excess nitrogen volumes

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in the stream reduce the temperature of the gas phase due to its low latent heat. Placing excessive amount of gas

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additives in the steam might cause inadequate temperature for mobilizing the heavy oil, thus reduce the efficiency of

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cycle steam. In this case, we reduce the composition of nitrogen to 40%. Later, we also compare the effect of

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injected gas additives on the heavy oil well production performance. In the base model, the steam was injection at

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380℃. In the flue-gas assisted steam injection process, the flue-gas and steam was injected at 20 Mpa. Since the

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reservoir burial depth is too deep, the injected steam quality was kept at 95%. The injector was constrained by the

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maximum injection pressure at 20 MPa. The maximum gas injection rate was specified at 500m3/day. Once the

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injection pressure goes above 20 MPa, the well constraint would converted automatically to a rate control. The

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minimum producing pressure was kept at 2 MPa. An overview of the low permeability heavy oil resources in the

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Middle East carbonates has been reported by Buza (2008). The reservoir characterization of carbonate reservoirs

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was shown in Fig.5. The reservoir oil viscosity is proportional with the oil density. Field production data showed

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that the recovery efficiency is commercially viable because there are abundant natural fractures in carbonate

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reservoirs. The production performance depends on factors such as the magnitude of oil viscosity reduction, fracture

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intensity and matrix minerals.

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3. Results and Discussion

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Grid sensitivity study was performed by discretizing one hydraulic fractured stage using different number of cells.

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For clarity, the Fig.6 only shows the sensitivity of recovery performance to three grid sizes. Sensitivity analyses by

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dividing one fracture stage into 5, 9, 11, 15, 17, 21, 27 grid blocks have been performed. The simulation results

27

demonstrated that the numerical dispersion is not significant as the grid size is refined. Using 21 grid blocks will

9

1

suffice to achieve reliable simulation results for the investigated cases. As can be seen in Fig.6, sensitivity analysis

2

of the gridding suggested that the difference between using 9 grid blocks and 21 blocks is within 0.1%.

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The numerical results was validated by history matching the field production data. The figure 7 and 8 showed the

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simulated results were in good agreement with the field production data (Well#Steam001). The history match on this

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well showed a good match between the simulated oil rate and cumulative water production. After we accomplished

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the match, then the history matched model was used for predictions of reservoir recovery performance process.

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The Willhite’s model was used to predict the wellbore heat losses in cyclic steam injection process (Prats, 1988).

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Based on the model prediction, the heat losses along the wellbore were shown in Fig.9. The predicted heat losses is

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very consistent with the measured values. The rate of heat loss per unit length of wellbore is proportional to the

10

wellbore depth. After the calculation of heat loss along the wellbore was clear, then it is feasible to begin modeling

11

the in-situ thermal steam injection process.

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3.1 The effect of matrix permeability

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To gain a better understanding of the matrix permeability effect on heavy oil production, a series of simulation cases

14

was carried out to explore the relationship between the recovery efficiency and reservoir matrix permeability. The

15

effect of matrix permeabilities on the recovery performance of flue-gas assisted cyclic steam injection process was

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shown in Fig.10. As seen, the cumulative oil recovery increases with increasing matrix permeability. The matrix

17

permeability is an essential factor to consider when assessing the feasibility of a heavy oil project. If the matrix

18

permeability of a heavy oil reservoir was below a certain limit, even implementing cyclic steam simulation would

19

have little effect on improved oil recovery. When the reservoir matrix permeability is under 0.01 mD, the heavy oil

20

is almost immobile by cyclic steam and flue-gas injection. The oil production rate and the corresponding average

21

reservoir pressure during cycle process was shown in Fig.11. It becomes obvious that the oil rate is diminishing with

22

increasing number of cycles, but the average reservoir pressure is essentially increasing. The oil rate from a single

23

hydraulic fracture stimulated volume can not maintain the designed rate at 40 m3/day. These results showed that

24

keeping an injection rate at 800 m3/day would exceed the injection pressure target limit (20,000 kpa). A higher level

25

of injection pressure target is required if we want to maintain this specified injection rate. If the actual injection

26

pressure was lower than the specified value, then the well would operate with the injection rate constraint. The

27

initial oil peak rate was high because of the reduced oil viscosity and increased reservoir pressure. As heat was

10

1

removed with the produced fluids and heat loss to the overburden and underlying rocks, the temperature of heated

2

zone declines. A sharp decline of oil rate in a cycle was observed, which couldn’t even maintain 10 m3/day. The

3

cumulative oil recovery was increasing progressively, but incremental oil recovery decreased. By using the flue-gas

4

assisted cyclic steam injection, it is feasible to recover more than 150,000 m3 oil from a 10-stage hydraulically

5

fractured horizontal well with 1-mD matrix permeability. There is huge improved oil recovery potential by

6

implementing more cycles, smaller fracture spacing and CO2 conjunction with steam injection.

7

3.2 The effect of injected stream composition on cyclic injection performance

8

The placement of various viscosity reducer with steam has been reported in the preceding discussions. To evaluate

9

the benefit of CO2 and flue gas on thermal recovery performance, different combination of gas composition in the

10

injection stream was compared. In this paper, the effect of flue-gas with steam, CO2 with steam and pure steam

11

injection was shown in Fig.12. We selected the matrix permeability of 1-mD and flue-gas coinjection with steam as

12

our base case in comparison with the CO2/steam cases. The results indicated that the CO2/steam coinjection yielded

13

higher oil recovery than flue-gas/steam and pure cyclic steam injection process. Despite CO2 is a poor candidate in

14

carrying heat, the solubility of carbon dioxide in oil phase and oil viscosity reduction is greater than nitrogen and

15

steam. A detailed analysis of the CO2, nitrogen and steam thermal properties was demonstrated in Fig. 13, 14 and 15.

16

The cumulative injected enthalpy of the CO2/steam is higher than flue-gas/steam and pure steam as shown in Fig.13.

17

This result provides an explanation on why the production response from CO2/steam injection is better than

18

nitrogen/steam or pure steam. Fig.14 compares the ideal-gas properties of gas phase enthalpy of steam, CO2 and

19

flue-gas. The cumulative enthalpy injection in place showed a consistent performance with the individual gas phase

20

enthalpy (shown in Fig.14). Because of the enthalpy carried by carbon dioxide with steam is higher, the total

21

injected enthalpy in reservoir is also greater. This also is an evidence that CO2/steam resulted in greater incremental

22

oil recovery than flue-gas and steam-only. Thermal conductivity determines the diffusion rate of energy from a high

23

temperature region to low temperature. Fig.15 shows the thermal conductivity of steam, CO2 and flue-gas at 1 bara

24

versus temperature. The thermal conductivity of the steam is higher than carbon dioxide and flue-gas. It suggests

25

that the addition of flue-gas or carbon dioxide have a role as thermal isolation to alleviate the heat loss along the

26

wellbore due to their low conductivities. Considering the low thermal conductivity of carbon dioxide and flue-gas,

27

their slug is able to advance further into the reservoir and contact more heavy oil.

11

1

There is appreciable difference between the CO2/steam injection recovery efficiency and the base-case flue-gas

2

injection. However, the total amount of cumulative gas injection for these two cases is the same. The addition of

3

CO2 in the cyclic steam injection process contribute significant increase in final recovery. The major benefit of CO2

4

additive includes viscosity reduction and CO2 solution in oil to form gas-drive effect. It was claimed that the CO2

5

swelling effect is negligible for incremental oil recovery in consideration of the fact that the thermal expansion of oil

6

is much higher than the CO2 swelling (Leung, 1983). A higher incremental oil recovery was obtained by using a

7

lower gas/steam ratio (CO2/steam injection). It could only be explained by that the benefits of adding CO2 in the

8

cyclic steam injection process overwhelmed the negative effect of its low latent heat.

9

3.3 The effect of injection method on cyclic injection performance

10

The production response of Fig.16 showed that alternating injection of steam with flue-gas achieved better

11

performance and higher oil recovery than coinjection of flue-gas with steam, although the same amount of flue-gas

12

and steam was injected for both cases. A sustained increase in oil recovery was observed, but the increase of oil rate

13

was diminishing. An explanation for this phenomena is that the saturation temperature and pressure of coinjection

14

mixture is lower than alternating injection of steam and flue-gas (Lawal, 2011). In the continuous injection process,

15

flue-gas is in admixture with steam which is less efficient in reducing the heavy oil viscosity than separate flue-gas

16

and steam for alternating injection manner. In similar arguments, the reservoir volume of injected mixture flue-

17

gas/steam is less than alternating injection. The recovery efficiency is more effective for alternating injection.

18

The pressure distribution during one cycle of steam injection process was demonstrated in Fig.17. As indicated from

19

the figures, the pressure increased during mixture steam injection. On the contrast, heated oil was withdrawn by the

20

hydraulic fracture. As time progresses, pressure decline propagates into the far colder portions of the stimulated

21

reservoir. During the production period, both the temperature and pressure decreases further by the removal of hot

22

fluids from the heated-zone. For instance, the pressure after 100 days production is lower than the 50 days. The

23

production response or steam reached distance in the low-permeability strata is not as significant as the high

24

permeability formations. Similarly, the steam saturation distribution during one cycle of steam injection process was

25

shown in Fig.18. The variation of steam saturation is in consistent with the reservoir pressure.

26

3.4 The effect of induced temperature dependent relative permeability on cyclic injection performance

12

1

Fig.19 shows the temperature and pressure profile after 200 days steam injection. During injection process, the

2

region surrounding the hydraulic fracture has the highest temperature and pressure. The heat loss to the adjacent

3

formation can be clearly seen as the temperature decreases from the hydraulic fracture to the adjacent formation.

4

The injection stream flows along the wellbore into the reservoir through the perforations and hydraulic fractures.

5

Heat loss to the formation involves many mechanisms such as a steady-state heat transfer across the annulus,

6

conduction through the casing steel and cement to the formation. Heat losses primarily occur in the inner tubing by

7

convective heat transfer, annular space (by heat radiation, convection and conduction) and heat conduction to the

8

formation. The detailed discussion of the temperature behavior as fluid moves from the wellbore to the surrounding

9

strata can refer to the literature (Green and Willhite, 1998). The temperature of the central hydraulic fracture is the

10

highest in the steam injection stage, while it gradually decreases away from the fracture. At the end of cycle

11

injection, the temperature of the entire fracture controlled region was higher than 100 oC. However, with

12

progressively more hot fluids being produced, the temperature of this region will decline. The condensed liquid

13

would form ahead of the steam front once the temperature decreased further below 100 oC. As a result, coexistence

14

of hot water bank, steam bank and oil bank is possible in the production cycle. The temperature profile at different

15

time interval of the first production cycle after 200 days injection was shown in Fig.20. It is evident that the

16

temperature loss was substantial in the first 200-days, but the rate was declined in the remaining production time.

17

Notice that the temperature variation of the hydraulic fracture was more sensitive than the matrix blocks. Since the

18

hydraulic fracture is the main conduit for fluid flow. Withdrawal of the heat energy was primarily populated by

19

hydraulic fractures.

20

A steady-state experiment was carried out to investigate the effect of induced temperature by steam injection on

21

relative permeability. In the relative permeability measurement procedure, oil and water are injected simultaneously

22

into the test core at constant rates and pressures. It is noted that the flow rates and pressure gradients were measured

23

only when the pressure drop across the core remained relatively constant.

24

(1) Initially, a confining pressure was applied on the system. Then the system was vacuumed for 5 hours to

25

eliminate the air. The test begins by saturating the core with brine water.

26

(2) After the core completely saturated with water, the permeability was measured at fully water saturated state.

27

During the process, it is assured that the confining pressure is higher than the injection pressure. The apparatus

13

1

was placed in the oven to heat the system to the reservoir temperature and remain stabilized during the

2

displacement process.

3

(3) Reservoir crude oil was injected into the core until steady state was reached. At this point, the irreducible water

4

saturation was established. The inlet flow rate and pressure drop across the core was measured and used in

5

Darcy’s law to calculate the relative permeability.

6 7 8 9

(4) Water and reservoir oil were injected simultaneously at the inlet until the system reached equilibrium. Similarly, the flow rates at the outlet and pressure drop across the core were measured at steady state. (5) Repeat the step four by injecting at different water/oil ratio. Thus it is able to establish the relative permeability at different water saturations.

10

The relationship between temperature and relative permeability was shown in Fig.21. It is clear that the residual oil

11

saturation decreased with increasing temperature. The mobility of heavy oil gradually increases as the experimental

12

temperature rises from 50 to 200 °C . It is also noticed that the irreducible water saturation is increasing as

13

temperature goes up. According to the kinetic theory, the motion of the particles is increased by raising the

14

temperature. When heat is added to the heavy oil reservoirs, the movement of the adsorbed molecules increases.

15

Heat can reduce the physical attraction between oil and reservoir rocks. It provides a chance for water molecules to

16

take over the position from the desorbed polar molecules. The removal of the polar molecules from the rock surface

17

and more adhering water molecules leads to an increasing of irreducible water saturation. Compared with the case

18

without considering the temperature effect, the oil rate and cumulative oil recovery was higher for the case including

19

the temperature dependent relative permeability (as shown in Fig.22). The improved oil recovery is attributed to the

20

interaction of increased irreducible water saturation, reduced oil viscosity and increased reservoir pressure. Similar

21

observations has been reported in the literature (Schembre et al., 2006; Akhlaghinia et al., 2013; Sedaee Sola et al.,

22

2007). It was concluded that the relative permeability of the non-wetting phase was improved by the temperature

23

effect.

24

3.5 Further discussion of CO2 assisted steam injection performance in the field practice

25

In order to evaluate the efficiency of CO2 assisted steam huff-n-puff process, it is interesting to present a field case.

26

Fig.23 shows a well production history of CO2 assisted steam huff-n-puff well production performance. The deep

27

well LB1-16 was produced at 2011. The oil rate declined substantially after about 1-year production. Then CO2 co-

14

1

injection with steam was carried out at 2012. It is clearly seen from the graph that the oil rate increased substantially

2

and the water cut decreased as well at the meantime of steam injection. Two cycles of CO2 assisted steam injection

3

were performed. The improved oil recovery was significant due to the injection of CO2. Table 9 summarizes the oil

4

field practice of CO2 effect on steam injection. Generally, CO2 addition in steam huff-n-puff process has the

5

potential to improve heavy oil recovery. The CO2 cycle efficiency is defined as the amount of enhanced oil

6

production by per ton of CO2 injection. The exchange rate of CO2 with crude oil lies within 0.6-2, which varies

7

significantly. Besides, the recovery efficiency of CO2 with steam considerably depends on the formation

8

heterogeneity. Before conducting the sensitivity studies, the model quality check was performed by history match

9

the PVT data of the field. Fig. 24 and Fig.25 shows the lab measured heavy oil density compared against the EOS

10

simulated values. As seen, the EOS predicted oil properties were in good agreement with the laboratory measured

11

data. The model verification was checked also by history match the field well production observed data.

12

In order to investigate the effect of CO2 dissolution in formation water on oil recovery efficiency, a series of mixture

13

CO2/water/heavy oil PVT experiments were carried. The composition of heavy oil was measured under different

14

CO2 mole fractions. Fig.26 shows the effect of CO2 solubility in water (molar fraction) on oil composition properties.

15

As CO2 dissolves in water, the fraction of CO2 mixture in oil phase is decreasing. Since CO2 has the potential to

16

extract intermediate hydrocarbons from the crude oil, the light and intermediate components of crude oil decreases

17

as the content of CO2 dissolves in oil phase increases (less CO2 in water phase). As a result, the heavy components

18

of oil increases due to more CO2 solution into the oil phase.

19

There are many factors that control the rate of CO2 dissolution in formation water, such as water salinity,

20

temperature and formation pressure. In order to consider the effect of CO2 solubility in water on ultimate recovery

21

efficiency, we compared different cases of CO2 solubility in water phase. The general Henry’s law was used in the

22

model to simulate the CO2’s dissolution in water. Fig.27 presents the effect CO2 dissolution in water phase on steam

23

huff-n-puff recovery efficiency. It indicates that more CO2 dissolution in formation water reduces the steam cycle

24

production efficiency. The results obtained in Fig.27 is very consistent with our field observations. If an acquirer

25

exists underneath the oil formation, the CO2 recovery efficiency compromises significantly. As CO2 goes into the

26

formation water, less CO2 would form miscibility with the oil phase. As a result, the efficiency of CO2 assisted

27

steam process is declined.

15

1

4. Conclusions

2

The use of hydraulic fracturing in conjunction with CO2, flue-gas assisted cyclic steam injection has been examined

3

in this paper for producing low permeability heavy oil reservoirs. The simulation results indicated that steam

4

injection with CO2 and flue-gas additives is an efficient method for mobilizing heavy oil. The positive production

5

responses from additive steam processes included: oil swelling effect, increase the size of the steam chamber, higher

6

injected enthalpy in place, oil viscosity reduction due to solubilization effects and improved relative permeability by

7

temperature effect. There is some synergistic effect on oil recovery by adding the additives in steam injection.

8

Substantial increases in reservoir pressure and temperature occurred during the injection cycle. Because of the low

9

thermal conductivity of carbon dioxide and nitrogen, their slug has a role to alleviate the heat losses to adjacent

10

formations and contacted more heavy oil. The presence of hydraulic fractures is crucial for fluids flow and

11

mobilizing the heavy oil to the producing wellbores. With the same amount of flue-gas and steam injected,

12

alternating injection of steam with flue-gas achieved better performance and higher oil recovery than coinjection of

13

flue-gas with steam. The experimental study clearly showed that the residual oil saturation decreases with increasing

14

temperature. Compared with the case without considering the temperature effect, the oil rate and cumulative oil

15

recovery is higher for the case including the temperature dependent relative permeability.

16

1.

17 18

injection process contributes to the improved oil recovery. 2.

19 20

By comparing the effect of injected stream composition, it was found that the addition of CO2 in the steam

The simulation results indicated that alternating injection of steam with flue-gas achieved better performance and higher oil recovery than coinjection of flue-gas with steam.

3.

Compared with the temperature independent relative permeability case, the oil rate and cumulative oil recovery

21

was higher for the case including the temperature dependent relative permeability. The experimental study

22

clearly showed that the residual oil saturation decreases with increasing temperature.

23

Acknowledgements

24

This work was support from Science Foundation of China University of Petroleum-Beijing at Karamay

25

RCYJ2017A-01-003, Innovation Talents Program of Karamay City 2018RC005A and Xinjiang Uygur Autonomous

26

Region Tianchi 100 talent plan is highly appreciated.

27

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16

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

fiL =fugacities in the liquid phase of component i

f iV =fugacities in the vapor phase of component i Fv =Vapor phase mole fraction n = moles; m = mass; M=molecular weight; Ki =Equilibrium constants for component i

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19 20

Atkinson, P. G., Celati, R., Corsi, R., and Kucuk, F. Behavior of the Bagnore Steam/CO2 Geothermal Reservoir, Italy. SPE J 1980; 20(04):228-238.

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Butler, R.M. A New Approach to the Modelling of Steam-assisted Gravity Drainage. JCPT 1985; 24(3): 42-51.

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Closmann, P.J. and Smith, R.A. Temperature Observations and Steam-Zone Rise in the Vicinity of a SteamHeated Fracture. SPE J. 1983; 23(4): 575-586.

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34 35 20

1 2 3 4

5 6

Fig.1 Schematic of well structure for cyclic steam injection process used in the Xinjiang field

7 8 9 10 11 12

Fig 2. Heavy oil rock core sample from well #25

13 14 15

Fig.3 Horizontal well drilling in heavy oil reservoirs with hydraulic fracturing treatment. Steam and CO2 huff-n-puff coinjection process via fracture was demonstrated. (Modified from Brown et al., 1990)

21

1 2

Fig.4 The model set up horizontal well with multiple hydraulic fracturing treatment

3 4

Fig.5 The Middle East HO carbonates matrix permeability and oil viscosity (Buza, 2008)

Cumulative oil production (m3)

14000 9 grid blocks 11 grid blocks 21 grid blocks

12000 10000 8000 6000 4000 2000 0 0

5 6

500

1000

1500 2000 Time (days)

2500

Fig.6 Effect of grid size on well production performance

22

3000

Oil Rate (m3/day)

100 90

Simulation results

80

Production observed data

70 60 50 40 30 20 10 0 0

200

400

600

800

1000

1200

Time (days)

1 2 Cumulative water production (m3)

Fig.7 History match results for oil rate

9000

Production observed data Simulation results

8000 7000 6000 5000 4000 3000 2000 1000 0 0

200

400

600 800 Time (days)

1000

3 4

Fig.8 History match results for cumulative water production

23

1200

Steam Temperature (C)

400 Calculated steam temperature 390

Measured value

380 370 360 350 340 200

700

1200 1700 2200 Wellbore depth (m)

2700

3200

1 2

Fig.9 Heat losses in the wellbore with different depths

Cumulative oil production, m3

35000 Km=100 mD 30000

Km = 10 mD Km = 1 mD

25000

Km = 0.1 mD 20000

Km = 0.01 mD

15000 10000 5000 0 0

3 4

500

1000

1500 2000 Time, days

2500

3000

3500

Fig.10 The performance of flue-gas assisted cyclic steam injection at different matrix permeabilities

24

1 2

Fig.11 Oil rate and the corresponding average reservoir pressure changes during cycle process 25,000

Cumulative Oil Recovery (m3)

CO2 coinjection with steam flue-gas coinjection with steam pure cyclic steam injection

20,000

15,000

10,000

5,000

0 0

3 4

400

800

1,200 1,600 Time (day)

2,000

2,400

2,800

3,200

Fig.12 Comparison of oil recovery for different injection streams

25

Enthalpy cumulative injection in place (J)

5.00e+14 CO2 coinjection with steam Flue-gas coinjection with steam Pure cyclic steam injection

4.00e+14

3.00e+14

2.00e+14

1.00e+14

0.00e+0 0

400

800

1 2

1,200 1,600 Time (day)

2,000

2,400

2,800

3,200

Fig.13 Cumulative enthalpy injection in place for different injection streams 25000 Steam Carbon dioxide

Enthalpy [kJ/Kmol]

20000

Flue-gas 15000

10000

5000

0 220

3 4

260

300

340

380

420

460

500

540

580

Temperature, K Fig.14 Comparison of ideal-gas properties of gas phase enthalpy

5 6

26

620

0.08

Thermal Conductivity [Btu/(h-ft-F)]

Steam 0.07 Carbon dioxide 0.06 Flue-gas 0.05 0.04 0.03 0.02 0.01 0 0

100

200

300

400

500

600

700

800

900

1000

Temperature, C

1 2

Fig.15 Thermal conductivity of steam, CO2 and N2 at 1 bara versus temperature

20,000

4.00e+11

15,000

3.00e+11

10,000

2.00e+11

5,000

1.00e+11

0

0.00e+0 0

3 4

Enthalpy Inje Rate SCTR (J/day)

Cumulative Oil Recovery (m3)

Coinjection flue gas with steam Alternating injection of flue-gas with steam Enthalpy Injection rate

400

800

1,200 1,600 2,000 2,400 2,800 3,200 Time (day)

Fig.16 Comparison of coinjection method with alternating injection of steam with flue-gas

27

kPa

1 kPa

2 3 4 5

Fig.17 The pressure (kPa) distribution during one cycle of steam injection process (The corresponding images from left to right represent the pressure distribution at initial condition, after 200 days injection, after 50 days depletion during production cycle, after 100 days production, after 150 days production, after 200 days production)

28

1

2 3 4 5

Fig.18 The steam saturation distribution during one cycle of steam injection process (The corresponding images from left to right represent the gas saturation distribution at initial condition, after 200 days injection, after 50 days depletion during production cycle, after 100 days production, after 150 days production, after 200 days production) 20,000

400

19,000

Pressure (kPa)

18,000

17,000

200

16,000

Temperature (C)

300

100 15,000

Hydraulic fracture Pressure 200.00 day Temperature 200.00 day

14,000 0

6 7

10

20 30 Distance (m)

40

0 50

Fig.19 The temperature and pressure distribution at the end of 1st steam injection cycle

29

400 Temperature at 200 day Temperature at 250 day Temperature at 300 day Temperature at 350 day Temperature at 400 day

Temperature (C)

300

200

100

Hydraulic fracture 0 0

10

1

20 Distance (m)

30

40

50

Fig.20 The temperature profile at different time interval of 1st production cycle

2 3

Relative Kr of heavy oil

1.0

50 C Kro 50 C Krw 100 Kro 100 Krw 150 Kro 150 Krw 200 C Kro

0.8 0.6 0.4 0.2 0.0 0.30

4 5

0.40

0.50

0.60 Sw

0.70

0.80

0.90

Fig.21 Measured relative permeability of heavy oil under different temperatures

30

60 Without temperature effect Temperature dependent relative permeability

15,000

Temperature dependent relative permeability Without temperature effect

Cumulative Oil Recovery (m3)

Oil Rate (m3/day)

50

40

30

20

10,000

5,000

10

0

0

0

1 2

400

800

1,200 Time (day)

1,600

2,000

2,400

0

400

800

1,200 Time (day)

1,600

Fig.22 The temperature dependent relative permeability effect of heavy oil production performance

3 4

2,000

Fig.23 Field case of CO2 assisted steam huff-n-puff well production performance

31

2,400

960 P=30 MPa

Heavy oil density, Kg/m3

950

P=25 MPa P=20 MPa

940

P=16 MPa P=14 MPa

930

P=12 MPa Simulation of P=30 Mpa

920

Simulation of P=25 Mpa Simulation of P=20 Mpa

910

Simulation of P=16 Mpa Simulation of P=14 Mpa

900 0

20

40

60

80

Simulation of P=12 Mpa

CO2 molar fraction in oil phase

1 2

Fig.24 The lab measured heavy oil density compared against the EOS simulated values

3 4

Fig. 25 The lab measured oil viscosity compared against the EOS simulated values

5

32

Component molar fraction

100 10 CO2=70% CO2=60%

1

CO2=54% CO2=50% CO2=45%

0.1

CO2=25%

0.01 0.001

1 2

C1 C2 C3 iC4 NC4 iC5 nC5 C6 C7 C8 C9+ Fig. 26 The effect of CO2 solubility in water (molar fraction) on oil composition properties

3 4

Fig.27 The effect CO2 dissolution in water phase on steam huff-n-puff recovery efficiency

5 6 7 8 9 10

33

1

Table 1.-Petrophysic properties from well coring data

2

Well

Depth (m)

Porosity(%)

Permeability(mD)

Oil saturation(%)

3

DF320

1110

22

550

65.2

DF321

1200

18

56

65.9

4

FZ025

1300

15.8

24

68.6

5

Z001

1400

12

15

59.8

Z002

1500

9.6

12

63.4

Z003

1900

8.2

5.6

65.1

Z33

2000

6.0

1.8

60.0

6 7 8

Table 2 The reservoir properties of the targeted heavy oil formation Sector Name

The depth of the reservoir formation (m)

A B C

1900 2000 2300

Pressure gradient (MPa/100m) 0.99 0.98 1

Reservoir pressure (Mpa)

Temperature gradient (℃/100m) 2.8 2.7 2.81

19 20 23

Reservoir temperature (℃ ) 51 54 65

9 10

Table 3 The fluid properties of the Xinjiang heavy oil field Sector Name

Oil density g/cm3

A B C

0.943 0.953 0.956

Oil viscosity (cp) Stock tank oil at 50 ℃ In-situ 12708 150 11013 286 26778 526

Freezing point (℃)

Paraffin content (%)

31.4 32.4 46

5.8 7.3 7.8

11 12 13

Table 4 The basic parameters used in the heat loss calculation Thermal properties

Value

Outside radius of the insulation

57.15 (mm)

Intside radius of the insulation

50.15 (mm)

Inside radius of casing

80.9 (mm)

Outside radius of casing

88.9 (mm)

Radius of cement

123.9 (mm)

Thermal conductivity of the casing

43.2 (W/m ∙ ℃)

Thermal conductivity of the tubing

43.2 (W/m ∙ ℃)

14 15 16 34

1

Table 5- Component properties input of the model for heavy oil thermal simulation Parameters

H2O

CO2

Heavy oil

Gas

Molecular weight, kg/gmole

0.018

0.044

0.6

0.017

Critical pressure, kPa

22048

7376

0

4598

o

374.15

31.05

0

-81.97

1.18e+7

8.62e+8

0

5.4e+4

Fourth coefficient Kv4, oC

-3816.44

-3103.39

0

-879.9

Fifth coefficient Kv5, oC

-227.02

-272.99

0

-265.99

Critical temperature, C First coefficient in the correlation for gas-liquid K value Kv1, kPa

2 3

Table 6- The lab measured rock and fluid properties in Xinjiang field used in the thermal simulation Parameters

Value

Reservoir permeability, md

10, 1, 0.1, 0.01

Hydraulic fracture permeability, md

800

Hydraulic fracture width, m

0.01

3

4

Rock heat capacity, J/(m *C)

2.57 × 10 6

Thermal conductivity of reservoir rock, J/(m*day*C)

1.29 × 105

Thermal conductivity of the water phase, J/(m*day*C)

5.99 × 10 4

Thermal conductivity of the oil phase, J/(m*day*C)

2.13 × 10 4

Thermal conductivity of the gas phase, J/(m*day*C)

1.9 × 10 3

Volumetric heat capacity of the overburden and underlying, J/(m3*C)

2.2 × 10 6

Thermal conductivity of the overburden and underburden, J/(m*day*C) 1.055 × 10 5 Table 7- The lab measured fluid viscosity properties from the Xinjiang field Temperature, C 30 40 50 70 90 110 130 150 170 190 210 230 250 270 290 300

Heavy oil viscosity (cp) 19054.61 6918.31 2270 530 215.42 98.24 47.84 27.5 15.23 10.56 6.98 5.17 3.76 2.89 2.24 2.04

5 35

Gas pressure (psi) 14.7 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000

Gas viscosity, µPa ⋅ s 33.1 34.2 35.8 38.1 42.4 88.3 180.2 284.8 414.3 551.6 685.6 813 933.6 1048.2 1157.6 1262.6

1

Table 8-Summary of the comparative sensitivity case studies

Case

Comparison

Matrix permeability, mD

Base case

1

Case 1

100

Case 2 Case 3

10

Matrix permeability effect

0.1

Case 4 Case 5 Case 6 Case 7

0.01 Injected stream effect Injection method

Injected fluids Flue gas (20% steam+ 40% CO2 + 40% N2) Flue gas (20% steam+ 40% CO2 + 40% N2) Flue gas (20% steam+ 40% CO2 + 40% N2) Flue gas (20% steam+ 40% CO2 + 40% N2) Flue gas (20% steam+ 40% CO2 + 40% N2)

Injection method Coinjection Coinjection Coinjection Coinjection Coinjection

1

20% steam+ 80% CO2

Coinjection

1

20% steam+ 80% N2

Coinjection

1

Flue gas (20% steam+ 40% CO2 + 40% N2)

Alternating injection

Cycle 200 days injection and 200 days production 200 days injection and 200 days production 200 days injection and 200 days production 200 days injection and 200 days production 200 days injection and 200 days production 200 days injection and 200 days production 200 days injection and 200 days production 200 days injection and 200 days production

2 3 4

Table 9-Field practice of CO2 addition in steam injection and its efficiency Sector Well

CO2 injection(tons)

Enhanced oil production (tons)

Cycle Efficiency

Effective days

JI7-1A JI7-2A JI7-3A JI7-4A JI7-5A JI7-6A JI7-7A

357 321 253 386 590 282 284

500 417 380 772 59 169 227

1.4 1.3 1.5 2 0.1 0.6 0.8

180 114 231 77 200 125 144

5

36

Highlights 

Use flue-gas assisted cyclic steam injection for improved oil recovery from low-permeability heavy oil reservoirs



Reveals the role of gaseous additives such as CO2 or flue-gas on the size of steam chamber



Evaluate the efficiency of different additives on reducing heat losses and improving the recovery performance in heavy oil reservoirs.