Steam assisted gravity drainage (SAGD) enjoys great advantages in the development of extra heavy oil reservoir such as high oil rate and favarable oil steam ratio. However, there are also disadvantages, such as intensive energy consumption, produced water recycle and disposal, that have impacts on the economics of SAGD projects. Furthermore, oil steam ratio declines and water cut rises when the SAGD comes into its later stage while great residual oil existing in the wedge zone. This paper proposes a new method, turning to in situ combustion (ISC) in the later SAGD, to improve the performance of the later SAGD. The feasibility and performance are both studied systematically. Firstly, a numerical model is established on the basis of reservoir and fluid parameters from a block in Xinjiang oil field, China, and then the performance characteristics in different stages of SAGD in extra heavy oil are studied. Particularly, characteristics of performance, features of temperature, pressure, steam chamber, distribution of residual oil in the later SAGD in extra heavy oil reservoir are deeply characterized. Combining these features and using physical simulation method, the feasibility of ISC in later SAGD in extra heavy oil reservoir has been discussed in terms of the effects of the oxidation kinetics characteristics, the thermal connectivity, the fuel supply, the coke deposit and the combustion front shape of extra heavy oil. Furthermore, the time when or before the steam chamber spreads to the edge of the SAGD well pair pattern is determined to be the optimum time to turn to ISC for the typical reservoir. By adding vertical wells for air injection in the middle of SAGD well pairs is the appropriate well pattern for ISC in the later SAGD. And perforating in the middle and lower interval is demonstrated to be the better method to control injection and production. Four stages in the process of ISC performance are determined and dissected. The study results indicate that stable combustion front shape and high production rate can be achieved after turning to ISC. Another 50.7% of the OOIP can be obtained in the ISC stage, regardless of 30% oil recovery in the SAGD stage.

Currently Block J6 is in the later stage of steam flooding after 27 years’ steam injection, its recovery factor is about 50%, and the water cut is more than 95%. Particularly, the present steam oil ratio is about 12 m3(CWE)/t which has reached the economic limit and is in ineffective development. Cores from four post steam flooding drilling wells show that only top 2-3m of the total 25-30m pay zone has a steam chamber which is the main steam channel and its residual oil saturation is about 20%, the other 22-27m pay zone is displaced by hot water and its oil saturation is 40-55%. A 3D physical simulation show the conventional steam flooding with full interval perforation quickly broke through from the top of reservoir, and the steam oil ratio rose rapidly from 5 m3(CWE)/t to 10 m3(CWE)/t. The recovery factor was only 20.1% at the time of steam breakthrough, and then it was in the phase of high steam oil ratio for a long time. During CO2 assisted steam flooding the whole perforated producer is switched into a low half perforated well, and the recovery factor increases from 20.1% to 81.1%, the steam oil ratio is 3.3m3(CWE)/t. There are three characteristics in CO2 assisted steam flooding stage, firstly there is a steam and CO2 assisted gravity drainage mode, steam chamber expands from the top 2-3cm to the total 20cm oil layer. Secondly, there is a stable emulsion foam oil, its water cut is 60-70%, CO2 liquid ratio is about 5:1 Sm3/t, CO2 is a kind of dispersed bubble so it is much more than the dissolved CO2 liquid ratio 2:1 Sm3/t. Thirdly, CO2 lows the heatloss to overburden and keeps the formation pressure. The calculation shows that the heat loss can be reduced by more than 10% in the top layer. A pilot test including 9 well patterns(49 wells) has been established, and its recovery factor will be up to 75%, and the steam oil ratio will up to 2 m3(CWE)/t, a good production performance is predicted optimistically.

As fire-flooding has strong adaptability to develop the reservoir, it can be considered as a follow-up EOR technology of the low economic profit and high oil recovery reservoirs flooded by water or steam. Because of the complicated secondary water and steam channels, fire-flooding in post-steam-injected reservoir is far different from that in original reservoir. In this paper, the mechanism and problems associated with development engineering of fire-flooding in post-steam-injected heavy oil reservoir was studied systematically by using 1D&3D physical simulation systems and reservoir numerical simulator. The temperature of combustion zone decreased and high-temperature zone enlarged because there existed secondary water formed during steam injection which could absorb and carry heat towards producers out of combustion front during fire flooding, but high saturation of water in layer caused by secondary water had less influence on the quantity of fuel deposit and air consumption. In the process of 3D fire flooding experiments, air override was observed during combustion front moving forward and resulted in a coke zone in the bottom of layer, and the ultimate recovery factor reached 65%~70% on fact that the saturation of oil within the coke zone was no more than 20%. The flooding model, well pattern, well spacing, and air injection rate was optimized according to the specific property and the existed well pattern in post-steam-injected heavy oil reservoir, and the key techniques of ignition, lifting, and anticorrosion was also selected in the same time. The pilot of fire flooding in H1 block in Xinjiang oil field was carried out since Dec. 2009 on the base of these research work, and now the pilot begin to show the better performance. The production oil is about 49t/d, and the water cut is stable below 70%, the air oil ratio is about 2000m 3 /t, the good performance is gained for this kind of abandoned post-steam-injected heavy oil reservoir.

It is challenging to enhance heavy oil recovery in the late stages of steam flooding. This challenge is due to the reduced residual oil saturation, the high steam-oil ratio, and the lower profitability. A field test of CO2-assisted steam flooding technology was carried out in the steam-flooded heavy oil reservoir in the J6 block of Xinjiang oil field (China). The field test showed a positive response to the CO2-assisted steam flooding treatment including a gradually increasing heavy oil production, a rise in formation pressure, a decrease in water cut, etc. The production wells in the test area mainly exhibited four types of production dynamics, while some production wells showed production dynamics that were completely different from those during steam flooding. After being flooded by CO2-assisted steam flooding, these wells exhibited a gravity drainage pattern without steam channeling issues, and hence could yield a stable oil production. Meanwhile, emulsified oil, together with CO2-foam, was observed to be produced in the production well, which agreed well with what was observed in the lab-scale tests. The reservoir-simulation-based prediction in the test reservoir shows that the CO2-assisted steam flooding technology can reduce the steam-oil ratio from 12 m3 (CWE)/t to 6 m3 (CWE)/t and yield a final recovery factor of 70%.

This study conducts a literature survey on the chemical steam additives tested in both lab and field settings from 1982 to present (2020). We summarize the major recovery mechanisms of both steam-based recovery process and steam-chemical-based recovery process. Next, we review the previous lab-scale/field-scale studies examining the applications of surfactants, alkali, and novel chemicals in the steam-based oil recovery process. Among the different surfactants studied, alpha-olefin sulfonate (AOS) and linear toluene sulfonate (LTS) are the recommended chemicals for their foam control/detergency effect. In particular, AOS was observed to perform especially well in residual oil saturation (ROS) reduction and sweep efficiency improvement when being co-injected with alkali. Application of organic alkali (alone or with a co-surfactant) has also drawn wide attention recently, but its efficacy in the field requires further investigation and the consumption of alkali by sands/clay is often an inevitable issue and, therefore, how to control the alkali loss requires further investigation. Novel chemical additives tested in the past five years include fatty acids (such as tail oil acid, TOA-Na+), Biodiesel (o/w emulsion), along with other types of chemical additives including switchable hydrophilicity tertiary amines (SHTA), chelating agents, Deep Eutectic Solvents (DES), graphite and SiO2 particles, ionic liquids and urea. High thermal stability of some of the novel chemicals and their potential in increasing displacement efficiency and ROS reduction efficiency in the lab studies require further investigation for their optimized application in the field settings to minimize the use of steam while improving the recovery effectively. This review reveals that when being properly applied, chemical additives can improve oil recovery via steam foam control, detergency effect (IFT reduction and wettability control), and viscosity reduction. In certain cases, microemulsion generation could be observed (o/w or w/o) with the addition of chemical additives at steam condition (which leads to recovery improvement), but the microemulsion effect on the conformance control (separate from the foamy effect), is lacking detailed investigation.