Super Heavy Oil Reservoir Research Articles

Experiments on Steam-Assisted Gravity Drainage with Coinjection of Noncondensable Gases during the Middle and Later Stages of Its Development in Super-Heavy Oil Reservoirs

Summary The problems of oil/steam ratio (OSR) and oil production decline are prominent during the middle/later stages of steam-assisted gravity drainage (SAGD) in superheavy oil reservoirs. Using noncondensable gas (NCG) by SAGD can reduce heat loss to the overburden and reduce carbon dioxide (CO2) emissions. However, to date, laboratory experiments have mainly been conducted to simulate NCG coinjection with steam in the early stage of SAGD. There has been limited research on the NCG coinjection into the mature SAGD steam chamber. For this study, five sets of 2D physical simulation experiments are introduced and designed based on NCG coinjection with steam into the sand-packed model. The influencing factors of steam-assisted and gas push (SAGP) are analyzed through experiments, including different NCGs [methane (CH4), CO2, and nitrogen (N2)] and coinjection of NCG at different times (i.e., during the lateral expansion and descending stages of the steam chamber). The results indicate that the mechanism of SAGP includes reducing the steam consumption, maintaining the pressure balance of the steam chamber, reducing the partial pressure of the steam, maintaining the quality of the steam, and improving the displacement efficiency of the steam during the lateral expansion of the steam chamber. In addition, the top gravity displacement is the primary mechanism during the later stage of pure gas injection, which manifests that the residual oil at the bottom of the steam chamber is further recovered by using the residual heat of the the steam chamber. Compared with SAGD, the recovery of CO2-assisted SAGD (CA-SAGD), CH4-assisted SAGD (MA-SAGD), and N2-assisted SAGD (NA-SAGD) increased 6.8%, 5.4%, and 4.4%, respectively. The NCG coinjection effect was better during the descending stage of steam chamber, and the oil recovery was 4.7% higher than that during the lateral expansion stage. The selection of NCG and coinjection timing plays a crucial role in improving the ultimate oil recovery and OSR during the middle and later stages of SAGD in superheavy oil reservoirs.

Comparative analysis of different foamy oil flow characteristics and production performances of two similar super-heavy oil reservoirs using microscopic visual physical experiments

Foamy oil flow is a potentially important reason for enhanced oil recovery (EOR) in super-heavy oil reservoirs during depressurized cold production (DCP). M oil reservoir and H oil reservoir located in Venezuela are typical super-heavy oil reservoirs with the foamy oil flow stage, and the properties of two reservoirs are similar. However, the production performances between two reservoirs in the stage foamy oil flow is quite different. In this paper, the novel microscopic visual physical experiments for foamy oil flow have been carried out to determine the flow characteristics of foamy oil and production performance. Three production stages of DCP are divided: stage I (the pressure greater than bubble point pressure), stage II (the pressure ranging from pseudo bubble point pressure to bubble point pressure), and stage III (the pressure lower than pseudo bubble point pressure). Then, the effects of different foamy oil flow characteristics in each production stage on production performances are investigated using comparative analysis method. The results show that the flow characteristics of the oil in the M and H oil reservoirs are both single-phase flow at stage I of DCP and two-phase flow at stage III of DCP. However, a phenomenon of strong foamy oil flow appeared in M oil reservoir while a phenomenon of weak foamy oil flow appeared in H oil reservoir at stage II of DCP. For the production performance, the oil rate, cumulative oil production and cumulative gas production of M oil reservoir increased obviously, while which of H oil reservoir increased slowly. The reason for the difference between the two oil reservoirs is that the super-heavy oil of M oil reservoir has more dissolved GOR and asphaltene content compared to H oil reservoir, and the pressure and temperature of M oil reservoir are more suitable for strong foamy oil flow.

Physical Simulation of Steam Absorption Characteristics in Horizontal Wells of Super Heavy Oil Reservoir

In the process of dual Horizontal well SAGD development of super heavy oil, the steam absorption balance of upper horizontal steam injection well is an important factor to determine the development effect of SAGD. The factors affecting the steam absorption of upper horizontal wells involve reservoir permeability, steam injection technology, steam injection parameters, etc. The physical simulation method is used to study the influence degree of each specific factor and improvement measures. Based on the similarity criterion, the reservoir scale model is designed and made according to the oilfield prototype, and the simulation experiment is carried out on the steam absorption characteristics and influencing factors along the horizontal wellbore. The experimental results show that the steam injection rate, non condensable gas, the location of the steam injection string and the reservoir permeability have great effects on the steam absorption of the reservoir. The heating uniformity along the horizontal well can be improved by properly increasing the steam injection speed, adding a certain amount of non condensable gas to the steam, and the position of the steam injection string end in the relatively low permeability area of the reservoir. This achievement has a strong guiding significance for improving the steam absorption balance of horizontal wells and improving the development level of dual level SAGD.

Application of SAGD technology in the development of super heavy oil reservoir buried medium deep

Continental super heavy oil reservoirs in China are characterized by deep burial depth, strong reservoir heterogeneity and high oil viscosity. The steam huff and puff technology are used to develop this type of reservoir, but in this development method, its oil recovery rate, oil steam ratio, and ultimate recovery are low. The benefit of the reservoir development is losses in this high cost per ton of oil. Many vertical wells injecting steam and one horizontal well-producing liquids pattern of SAGD technology (abbreviated as VERTIHORIONATAL pattern SAGD) were Innovated to solve the problems based on SAGD technology introduced from Canada. The SAGD technology introduced in Canada was made of double horizontal wells. The above horizontal well injects steam and the other horizontal well produces liquids continued (abbreviated as DOUBLE HORIZONTAL pattern SAGD). The VERTIHORIONATAL SAGD technology makes full use of the original well pattern of huff and puff and takes advantage of the thermal connectivity and underground temperature field formed by early development; At the same time, the VERTIHORIONATAL pattern SAGD technology can effectively solve the problem of steam cavity uneven expansion caused by reservoir heterogeneity by adjusting the location of steam injection vertical wells. It can also balance the liquid production in good horizontal sections and improve steam cavity formation speed by adjusting steam injection well sections and steam injection parameters. The technology has been successfully applied in the medium-deep super heavy oil reservoir in the Shu-1 area, Du84 block, Liaohe Oilfield. Seven oil wells with a daily output of 100 tons have been cultivated, and a stable production of million tons for four consecutive years. It has been built as China’s largest SAGD development demonstration area for medium-deep super-heavy oil.

Optimization of Efficient Development Modes of Offshore Heavy Oil and Development Planning of Potential Reserves in China

Thermal recovery is still the most important means to increase heavy oil EOR. With the increase in the recovery factor and the difficulty of exploiting new exploration reserves, the efficient utilization of offshore heavy oil reserves has attracted much attention. However, due to the challenges of high development investments, high operating costs, platform safety factors, and high economic cumulative yield, the offshore heavy oil reserves of nearly 700 million tons have not been effectively utilized. In this paper, Chinese offshore heavy oil reserves were taken as the research object. The indoor one-dimensional experiments were carried out to optimize an applicable development method, and the superheated steam huff and puff was selected as the injection medium for high-speed and high-efficiency development of offshore heavy oil, which verified the great potential of the application of superheated steam in offshore heavy oil thermal recovery. A numerical simulation model for offshore heavy oil superheated steam injection development was established, and a dynamic model considering the thermal cracking of heavy oil was established through historical matching. Through the field numerical simulation models, the whole process development mode of a single sand body, thin interbedded reservoir superheated steam huff and puff turning to superheated steam flooding, and thick layer super heavy oil reservoir with bottom water sidetracking after superheated steam huff and puff for eight cycles was established. Through the numerical simulation method and grey correlation method, the main control factors of superheated steam development of different types of heavy oil reservoirs were determined, and the cumulative oil production charts of different types of reservoirs under the influence of the main control factors were built. The economic evaluation model of superheated steam development of offshore heavy oil was established. Combining multi-specialty of geological, reservoir engineering, drilling and completion, oceanographic engineering, economics, the economic limits of steam injection development under different reserve scales, and engineering conditions of offshore heavy oilfields were clarified. At last, we planned the economic production mode of undeveloped reserves and predicted the construction profile of superheated steam capacity of offshore heavy oil using the production charts and the economic charts. The research results clarify the great potential of thermal recovery development of offshore heavy oil, provide an important basis for the economic development of offshore heavy oil undeveloped reserves, and also provide an important decision for the sustainable and stable production of global heavy oil reservoirs.

Research on Remaining Oil Characterization in Superheavy Oil Reservoir by Microgravity Exploration

Some physical processes such as oil and gas development, metal deposit collection, and groundwater resource migration can cause density changes, for which microgravity monitoring is the most intuitive method to monitor the density change process. Based on the basic principle of microgravity measurement and the idea of multiscale separation, a multiscale, second-order, surface-fitting, residual gravity anomaly extraction method is proposed to separate superimposed microgravity fields. In this method, regional fields of different scales are fitted and calculated successively with the measurement points as the center, so as to separate the gravity anomalies produced by different-depth density bodies. Results from actual data show that this method extracts the reservoir’s residual density characteristics of plane gravity anomaly on the basis of remaining oil distribution characteristics, consistent with reservoir numerical simulation results. A three-dimensional least-squares inversion of the method for extracting residual gravity anomaly was carried out, with the inversion results consistent with the results of vertical remaining oil distribution characteristics and well-test production results.

Simulation and Production Optimization on Enhanced Oil Recovery during the Middle and Late Period for SAGD Development in Ultraheavy Oil Reservoirs with Interlayers

Previous studies on the technique for using the remaining oil are incomplete and inaccurate according to the position of the interlayer of the Steam-Assisted Gravity Drainage (SAGD) technique, and comparative studies of infilled horizontal wells are lacking. In this study, the SAGD well pair in the superheavy oil reservoir in the Z block in the Xinjiang Oilfield, China, was taken as an example. According to the reservoir’s geological parameters and production parameters, a typical well group geological model was created for the first time. The model divided the well groups in block Z into three categories according to the position of the interlayer, the production degree of the horizontal section, the oil recovery ratio, and the available degree of reserve control. According to the geological classification results, different typical well groups without an interlayer, with an interlayer located above the steam injection well, and with an interlayer located between the well pairs were classified and analyzed using numerical simulations. This was the first time the infilled horizontal well technique was compared with the infilled vertical well-assisted SAGD technique. In addition, the steam chamber connection law of the infilled vertical well-assisted SAGD was clarified. The results show that for reservoirs without an interlayer, the use of infilled horizontal well-assisted SAGD could speed up the lateral connection of the steam chambers and reduce the residual oil saturation. For reservoirs with a low production degree in the horizontal section and that are affected by an interlayer, an infilled vertical injector could be used with the assisted SAGD technique to increase the oil recovery by 5%–13%. The results of this study provided strong guidance for the next step in using enhanced oil recovery techniques to achieve traditional SAGD production from superheavy oil reservoirs with an interlayer.

Fuzzy methods to evaluate the development effects of SAGD technology and its application during the middle and later stages of super-heavy oil reservoirs

The problems of energy consumption and decreasing production are prominent during the middle and later stages of steam-assisted gravity drainage (SAGD) in super-heavy oil reservoirs. Geological parameters and production parameters have an important impact on the development effects. However, there is no quantitative method to evaluate production effects of SAGD during the middle and later stages. In order to fill this gap, this study proposed a new approach to quantitatively evaluate the development effects of SAGD by considering the geological and production parameters for super-heavy reservoirs. Where, the primary factors controlling reservoir’s characteristics and development effects of SAGD were determined by using numerical simulation method. There are 42 well pairs that have already entered the middle and later stages using SAGD in the Xinjiang oil field, China, which were taken as an example. Firstly, a fuzzy cluster analysis model was established to classify reservoir by considering three geological indicators. The results indicated the potential of production for each well pair. Then a fuzzy comprehensive evaluation model was established to evaluate development effects by considering five production indicators. The new standards and ranking of evaluation indicators were quantitatively confirmed by using analytic hierarchy processes. Finally, the approach combined reservoirs classification and development effects evaluation to provide a quantitative and comprehensive evaluation of each well pair. The oil recovery ratio and utilization degree of the horizontal section can clearly reflect the development effects according to comprehensive evaluation results, which means that when the well group meets the recovery factor less than 3.0% and the utilization degree of horizontal section less than 85.0%, the development effects are evaluated as “Category III”. Based on the evaluation results, the corresponding follow-up adjustment measures can be adopted. This study has guidance on the development of technical countermeasures for different types of well pairs.

Prediction of top water flow rate to SAGD steam chamber and its impact on thermal efficiency

The Guantao Formation in the Block Du 84 of the Liaohe Oilfield of Northeastern China is a super heavy oil reservoir surrounded by top water, side and bottom water. Commercial development started in 1999 using vertical well Cyclic Steam Stimulation (CSS), with anticipated oil recovery factor of less than 25%. To improve the ultimate oil recovery, a pilot test of SAGD as a follow-up to CSS began in 2005 using a combination of infill horizontal wells with existing vertical wells; and the commercial expansion began in 2008 as a result of the encouraging results from pilot test. The current recovery factor over the entire development area has exceeded 45% of OOIP, with the pilot test area exceeding 68% of OOIP, and the ultimate recovery factor is predicted to exceed 70%. As the steam chamber becomes more mature and continues expanding upward, the risk of communication with the top water increases. Due to high pressure (>6.0 MPa) in the top water layer, it is not practical to balance the operating pressure in the steam chamber under the current economic conditions. The early forecasting of top water flow rates is important to assess its potential impact on SAGD performance and to formulate operating strategies for the late stage of SAGD development. In this paper, a theoretical model for predicting flow rate of top water to the SAGD chamber is established based on the incorporation of fluid flow and heat transfer mechanisms in porous media in the reservoir (barrier layer) between the steam chamber and the top water. The influence of barrier layer thickness, permeability, crude oil viscosity distribution and operating pressures in the steam chamber on the flow rate of the top water are studied. The flow of the top water into the steam chamber will lower oil to steam ratio (OSR) and the recovery process may become uneconomic when top water flow rate exceeds the current steam injection rate per well pair. The presence of high-viscosity “asphalt shell” layers near the bottom of the top water has limited mitigation effect on the flow of the top water. Under current operating conditions and 3.0 MPa pressure differential between the top water layer and steam chamber, 10 m of minimum thickness of barrier layer should be maintained to effectively mitigate the risk from inflow of top water.

Vertical-well-assisted SAGD dilation process in heterogeneous super-heavy oil reservoirs: Numerical simulations

PetroChina’s Karamay heavy oil reservoirs mostly comprise Jurassic deposits of braided fluvial facies that have a low porosity, extremely high bitumen viscosity, and strong heterogeneities within the reservoir. Steam-assisted gravity drainage (SAGD) dilation start-up has been proven an efficient reservoir geomechanical stimulation method as it shortens the steam circulation time, reduces steam usage, and increases the oil production rates. This method worked well on relatively good-quality oil sand reservoirs. However, for reservoirs with heterogeneous reservoir properties along the SAGD well, field well production data indicated the presence of non-uniform steam chambers in post-dilation SAGD wells. Enhanced dilation methods, such as vertical-well-assisted SAGD dilation (VW-SAGD-Dilation) are have been used, and field pilot tests have yielded promising results. This reservoir stimulation process utilizes one or more vertical wells beside the SAGD well to initiate the formation of dilation zones that connect to the dilation zone formed during the conventional SAGD dilation start-up. Compared with the normal SAGD dilation start-up, this composite dilation process creates a uniform dilation zone along the SAGD well, thus improving the thermal conformance and well productivity. The vertical well and SAGD well are connected by this composite dilation zone, which enables the combined use of the SAGD process and cyclic steam stimulation process. This paper presents our understanding and numerical case studies of this enhanced dilation strategy. The well production data from the post-dilation wells were positive (uniform steam chamber growth and higher oil rate), which highlights the promising potential of using geomechanical dilation as a reservoir stimulation method to create a large stimulated reservoir volume in heterogeneous super-heavy oil reservoirs.

Experimental Study on the Process of eMSAGP

While SAGD (Steam Assisted Gravity Drainage) has been successfully deployed in recovering heavy oil/oil sand reservoirs, it suffered from low OSR (Oil-Steam-Rate) and chamber growth rate in producing super heavy oil. The SAGP technology is to inject Non-Condensable Gas (NCG) into the reservoir with steam in the SAGD process. By partial pressure effect of NCG, SAGP reduces the heat loss to overburden, thus greatly increasing OSR and reducing the demand for steam. However, it still faces the challenge of uneconomic oil rate. Introducing infill well and operating it in flooding manner, enhanced Modified Steam Assisted Gas Push (eMSAGP) can significantly speed up the growth of steam chamber and improve oil production. This work presented the physical simulation results of eMSAGP and evaluated the feasibility of its application in super heavy oil reservoir.

Reservoir simulation of air injection assisted in situ upgrading process via subsurface electrical heating based on the horizontal well

Heat transfer rate is slow during the in-situ upgrading process (ISU) via underground electrical heating, which is suitable for developing super heavy oil and oil shale reservoir. Considering the advantages of air injection process and horizontal well technology, an air injection assisted in situ upgrading process (AAISU) based on the horizontal well have been proposed and simulated. Reservoir simulation results show that air injection can improve heat transfer rate, enhance oil recovery by 11.4% and improve the energy efficiency from 4.54 GJ/GJ to 8.15 GJ/GJ comparing to the ISU process without air injection. Heating temperature and air injection rate are important for the AAISU process. When the heating temperature increase, the heat transfer rate and oil recovery increase, however, the energy efficiency are reduced stead. As for the effect of air injection rate, when the air injection rate increase from 500-4000 m3/day, the oil recovery and energy efficiency are rise first and then dropped, and the oil recovery and energy efficiency are the greatest when the air injection rate is 1000 m3/day.

A semi-analytical model for predicting inflow profile of long horizontal wells in super-heavy foamy oil reservoir

In most super-heavy oil reservoirs, depletion recovery is one of the important cold recovery methods accompanied by foamy oil production. However, the inflow profiles of horizontal wells in super-heavy foamy oil reservoirs cannot be obtained by conventional methods at present. In this study, a semi-analytical model which couples the wellbore and reservoir was established to predict the inflow profile of horizontal wells in super-heavy foamy oil reservoirs with cold production method. The coupled wellbore/reservoir model is based on the prediction of the dynamic physical property parameters of foamy oil, and employs reservoir engineering methods, such as the microelement, mirror reflection, and potential function methods. The numerical solution was obtained by applying iteration method in MATLAB. Meanwhile, the model accounts for formation heterogeneity along the horizontal well that has never been considered before and pressure drop loss along the horizontal wellbore. The model was applied to a field case, and the calculation results were compared with those predicted by using the Joshi and Furui productivity formulas. It showed that the developed model led to the smallest errors from field production data, which further verifies the accuracy of the model. Moreover, sensitivity analysis is conducted by changing the permeability distribution along the horizontal well and the length of the horizontal section based on the established model. And the results are instructive for horizontal well optimization design. In short, this model is of great significance for productivity calculations, horizontal well design optimization, and production predictions of cold production with horizontal wells in super-heavy oil reservoirs.

Scaled physical experiments on drainage mechanisms of solvent-expanded SAGD in super-heavy oil reservoirs

In view of high oil viscosity at high temperatures, slow steam chamber expansion rate, low oil rate, and low oil/steam ratio of domestic super heavy oil blocks developed with dual-horizontal well steam assisted gravity drainage (SAGD), the solvent-aided oil viscosity reduction tests were carried out, based on which the analytical equations and similarity laws of solvent-expanded SAGD (ES-SAGD) were deduced. The large 2-D ES-SAGD scaled physical simulation experiments were conducted to compare the SAGD performances of the conventional steam and two formulas of solvent-steam system. The experimental results show that the light hydrocarbon solvents have good viscosity reduction effects to oil, and the oil reduction ratio can reach 96.5% by adding 5% N-hexane at 50 °C. Moreover, adding light hydrocarbon solvent (10% in the experiments) into the steam can bring the oil viscosity reduction effect of solvent and high temperature steam into play, speed up the lateral steam chamber expansion rate, increase the oil drainage rate and enhance the oil recovery degree. Adding 1% of xylene into the steam-solvent system can dissolve the asphalt to reduce asphalt precipitation, reduce the porous flow resistance and further enhance the oil recovery factor. The ES-SAGD recovery by reusing the solvents can realize replacement of the steam with small amount of solvents. Although currently higher in cost, the technology has the advantages of higher oil drainage rate, reduced production period, and enhanced oil recovery. The ES-SAGD theoretical model by modifying the SAGD model based on the oil viscosity reduction characteristics of solvents has been validated by the experiments and can be applied in ES-SAGD production predictions.

Review on the effective recovery of SAGD production for extra and super heavy oil reservoirs

Industrial development of extra and super heavy oil as an important energy resource substitute has been achieved worldwide. Steam-assisted gravity drainage (SAGD) is one of the most important recovery methods for extra and super heavy oil reservoirs. In this review paper, the following points of SAGD have been discussed: (1) mechanism, influencing factors and application criteria; (2) field application and experimental study; (3) analytical and reservoir simulation models; and (4) current research progress and future application of multi-medium-assisted SAGD. This study gives an overview of the current status and challenges of and solutions for the SAGD technology and provides reference for the effective recovery of extra and super heavy oil reservoirs.

Feasibility Study on Chemical Flooding in Super High Porosity and Permeability Heavy Oil Reservoir

In this paper, the feasibility study of chemical flooding is carried out for ultra-high porosity and high permeability heavy oil field with permeability higher than 10 μm2 and porosity greater than 35%. The viscosity-concentration relationship of four kinds of oil flooding systems such as hydrolyzed polyacrylamide, structural polymer A, structural polymer B and gel was studied. The results showed that the viscosity of ordinary polymer and structural polymer B was lower compared with other two types of oil displacement agents, and the viscosity of structural polymer A was higher. The higher the concentration, the higher the viscosity retention rate. The gel system has the highest viscosity and best anti-shear ability. The resistance coefficient and residual resistance coefficient of structural polymer A and gel system were further studied. The results show that permeability, velocity and polymer concentration all affect the resistance coefficient and residual resistance coefficient. From the point of view of resistance establishment ability, it is considered that structural polymer A is not suitable for permeability formation above 10 μm2. Gel system has stronger ability to establish resistance coefficient than structural polymer A flooding system, and it is more feasible for formation system with permeability above 10 μm2.

Significant effect of compositional grading on SAGD performance in a fractured carbonate heavy oil reservoir

In reservoir simulation, the fluid composition is usually assumed uniform for the whole reservoir, while in many reservoirs, oil and gas composition changes with depth. This phenomenon which is known as compositional grading could be significant in heavy and super heavy oil reservoirs. In these reservoirs, biodegradation and asphaltene precipitation are considered as the main reasons behind this phenomenon. Compositional grading in heavy oil reservoirs could affect fluid viscosity and vaporizing–condensing mechanism in steam-assisted gravity drainage (SAGD) operations. In this paper, through a simulation study, one of the Iranian heavy oil reservoirs which have a significant compositional grading was selected to investigate the effect of compositional grading on the performance of simulated SAGD method. The reservoir is a fractured carbonate reservoir, and its compositional grading is maintained because of the lack of convection inside the reservoir. To verify the importance of compositional grading, the performance results of the SAGD method for compositional grading case were compared with that of uniform composition case. The result showed that ignoring compositional grading would lead to underestimation of ultimate recovery in the fractured model. The study of SAGD process in a non-fractured reservoir model showed that considering compositional grading has an insignificant effect on SAGD performance.

Experimental study of CO2 solubility on the oil recovery enhancement of heavy oil reservoirs

The sufficient energy to transfer the crude oil to the surficial wellbore facilities would be reduced dramatically which was done by CO2, especially for heavy and super-heavy oil reservoirs. The objective of this comprehensive study is to measure the considerable influence of CO2 solubility on the recovery factor, density, viscosity at different pressures and temperatures. According to the results of this study, recovery factor at the pressure of 0.2 MPa and 0.5 MPa experienced the lowest recovery factor among other pressures. They were about 38.37% and 43.81% after the injection of about 15 pore volumes of CO2. For the pressures of 1 MPa, 2 MPa, 3 MPa, and 4 MPa, at the first stages of CO2 injection (up to 3 pore volumes of CO2 injection), the recovery factor experienced the same value. Since then, by the increase in pressure from 1 to 4 MPa, the recovery factor was increased slightly. Moreover, recovery factor at the temperature of 333 K was measured about 34.5%. The measured recovery factor for other temperatures was 40.17%, 47.68%, 51.97%, 58.42%, and 63.54% at the temperature of 363 K, 393 K, 423 K, 453 K, and 483 K, respectively. On the other hand, the density of heavy oil which was saturated with CO2 was decreased with the increase in pressure and temperature and the higher temperatures caused the lower effect on the viscosity and density of heavy oil. Consequently, the dissolution of CO2 had decreased the heavy oil viscosity in the higher temperatures and pressures, and due to the increase in pressure and temperature, the heavy oil recovery factor was increased. Furthermore, the recovery factor for the 70 mL min−1 of CO2 injection was lower than the 700 mL min−1 of CO2 injection.

Air-SAGD technology for super-heavy oil reservoirs

Abstract The air oxidation of super-heavy oil at low temperature was studied in laboratory and its influences on oil viscosity, component and steam sweep efficiency before and after air-injection were analyzed. The feasibility, operation mode and air flooding effect at the late stage of steam assisted gravity drainage (SAGD) were investigated by numerical simulation. The experimental results show for vertical-horizontal well pair SAGD test area of Xing VI Formation in Block Du 84 of Liaohe Oilfield, the low temperature oxidation occurred between 150–250 °C (steam chamber temperature), the oil viscosity increased greatly after low temperature oxidation, consequently, the oil displacement efficiency dropped sharply. Three development methods in the late stage of SAGD were simulated, i.e., steam + air low temperature oxidation, only air low temperature oxidation and only air high temperature oxidation. By comparing production dynamic curves and residual oil distribution etc., high temperature oxidation reduced the heat loss in late stage of SAGD, recovered the residual oil effectively, and prolonged reservoir development time.

Study on the Flow Characteristics of Shengli Oilfield Super Heavy Oil

Objective:The rheological properties of oil severely affect the determination of percolation theory, development program, production technology and oil-gathering and transferring process, especially for super heavy oil reservoirs. This paper illustrated the basic seepage morphology of super heavy oil in micro pores based on its rheological characteristics.Methods:The non-linear flow law and start-up pressure gradient of super heavy oil under irreducible water saturation at different temperatures were performed with different permeable sand packs. Meanwhile, the empirical formulas between start-up pressure gradient, the parameters describing the velocity-pressure drop curve and the ratio of gas permeability of a core to fluid viscosity were established.Results:The results demonstrate that temperature and core permeability have significant effect on the non-linear flow characteristics of super heavy oil. The relationship between start-up pressure gradient of oil, the parameters representing the velocity-pressure drop curve and the ratio of core permeability to fluid viscosity could be described as a power function.Conclusion:Above all, the quantitative description of the seepage law of super heavy oil reservoir was proposed in this paper, and finally the empirical diagram for determining the minimum and maximum start-up pressure of heavy oil with different viscosity in different permeable formations was obtained.