Extra Heavy Oil Reservoirs Research Articles

Numerical simulation on characteristics and mechanisms of steam-assisted in-situ combustion in extra-heavy oil reservoirs

Extra-heavy oil reservoirs, especially post-steam injection, continue to challenge performance of in-situ combustion (ISC), resulting in problems such as poor effect and slow startup. A novel enhanced oil recovery process, steam-assisted in-situ combustion (SAISC), is proposed. Using the Hongqian 1 Block as a case study, the model analyzes and elucidates production performance, combustion characteristics, oil displacement mechanisms, and mutual coupling effects associated with SAISC. Heat relationship analysis confirms feasibility of SAISC, while its applicability hinges on viscosity and the steam-air ratio, with economic limit calculations further demonstrating technique's superiority. The results show that injected steam during the SAISC process absorbs retained heat in the rock of the combustion zone through heat exchange, transforming into superheated steam. Steam condensation is delayed, and the condensation zone is expanded by about 10 m. The water and oil phase velocities in the condensation zone are both increased by 33 %, resulting in a production increase of over 40 %. Steam is more suitable than water as the heat-carrying fluid for SAISC, with a recommended steam-air ratio of approximately 4.0. When the oil price exceeds 60 USD/bbl, developing with SAISC technology yields an economic surplus. This study provides insights into improving the development effect in similar reservoirs.

Combustion behavior and effluent liquid properties in extra-heavy crude oil reservoirs developed by steam huff and puff

In recent years, interest in in-situ combustion (ISC) as an alternative technique for extra-heavy crude oil reservoirs subjected to steam huff and puff has grown significantly; however, the ISC behavior and effluent liquid properties in such oil reservoirs remain under-explored. In this work, the combustion tube (CT) was used to investigate the combustion behavior of extra-heavy crude oil. Also, the effluent liquid properties during ISC were analyzed comprehensively. The results revealed that when the secondary water bodies (SWB) were present at the injection end of CT, a stable combustion front advanced, causing a gradual temperature rise and a CO2 concentration above 12 % in the effluent gas. This suggested that steam injection wells in these reservoirs were suitable candidates for subsequent air injection after steam huff and puff. Conversely, when the SWB was located at the production end of CT, the peak temperature of combustion decreased, indicating a transition to medium-temperature combustion and unstable combustion front advancement, making steam injection wells unsuitable for ISC as production ones. Three key criteria for evaluating ISC effectiveness in extra-heavy crude oil were: (1) the intensity of –CH2 and –CH3 peaks, (2) the C-O absorption peak between 1100 and 1000 cm−1, and (3) the distribution of characteristic peaks around 750 cm−1. A significant decrease in these peaks indicated high-temperature combustion and substantial oil upgrading. Also, the presence of alkynes suggested extensive thermal cracking and a stable combustion front. The anion concentration of effluent water increased compared to crude water, but the relationship between water ion concentration and combustion state was weak, without a discernible pattern.

Experimental study on thermochemical composite flooding mechanism of extra heavy oil reservoirs with erosion channels

Experimental study on thermochemical composite flooding mechanism of extra heavy oil reservoirs with erosion channels

A modified vertical-horizontal well pattern for enhancing in-situ combustion performance in extra-heavy oil reservoirs

A proper well pattern is critical for the efficient and economical exploitation of heavy oil and bitumen during the in-situ combustion (ISC). This paper brings a modified vertical-horizontal well pattern named the modified THAI process using additional injectors in staggered line drive with auxiliary gas producer wells and investigates its ISC performance using a 3D experimental simulation. The burning stability, spatial distribution of coke zone, pressure difference, and extension features of combustion chamber are studied and analyzed. Results show that a better burning state and stable propagation for the combustion front can be achieved in this modified well pattern. Spatial distribution of coke zone structure manifests a larger sweep volume of combustion chamber and a lower extent of combustion override. Combustion chamber extension characteristics are intuitively displayed by the variation of 350 °C isothermal surfaces, and its sweep volume finally enlarges to 53032.55 cm3 with a volumetric sweep coefficient of 47.95%. The production well intermittent shutdown (PWIS) method can improve unfavorable expansion behaviors of combustion chamber with little impact on the burning state and pressure difference. The oil displacement efficiency eventually reaches 85.6%. This well pattern exhibits significant potential for enhancing in-situ combustion performance, contributing to the economic and efficient exploitation of oil in commercial ISC application.

Current Status and Future Trends of In Situ Catalytic Upgrading of Extra Heavy Oil

In situ catalytic upgrading of heavy oil decomposes viscous heavy oil underground through a series of complex chemical and physical reactions with the aid of an injected catalyst, and permits the resulting lighter components to flow to the producer under a normal pressure drive. By eliminating or substantially reducing the use of steam, which is prevalently used in current heavy oil productions worldwide and is a potent source of contamination concerns if not treated properly, in situ catalytic upgrading is intrinsically environmental-friendly and widely regarded as one of the promising techniques routes to decarbonize the oil industry. The present review provides a state-of-the-art summarization of the technologies of in situ catalytic upgrading and viscosity reduction in heavy oil from the aspects of catalyst selections, catalytic mechanisms, catalytic methods, and applications. The various types of widely used catalysts are compared and discussed in detail. Factors that impact the efficacy of the in situ upgrading of heavy oil are presented. The challenges and recommendations for future development are also furnished. This in-depth review is intended to give a well-rounded introduction to critical aspects on which the in situ catalytic application can shed light in the development of the world’s extra heavy oil reservoirs.

Development scheme screening considering reservoir damage based on the AHP model

The development process of oil and gas fields is affected by engineering and geology. Reservoir damage is significant as a bridge connecting these two disciplines. The life cycle of oil and gas fields can be prolonged by making development plans that consider reservoir damage. Therefore, this study performed experiments and discusses a Cretaceous reservoir development in the Chun17 block of the Chunguang Oilfield. We have carried out five sensitivity experiments on typical cores from the block, and analyzed lithology, physical properties, and crude oil. A mathematical model based on the Analytic Hierarchy Process (AHP) was then established based on the core data.Overall, the reservoir in the study area has ultra-high porosity and high permeability. The reservoir has moderately strong water sensitivity (damage rate is 38 ~ 90%) and moderately strong alkali sensitivity (damage rate is 22 ~ 75%). The crude oil belongs to extra-heavy oil reservoirs (containing 2.43% wax, 0.96% sulfur, 20.25 m% gum, 7.35 m% asphalt, 38.26 m% saturated hydrocarbon, and 27.51 m%). The crude oil is sensitive to temperature changes. Based on the AHP model analysis, the development scheme chooses the third (weight 0.1757) of the conventional analytic results of AHP; the Thermal oil production C1 scheme has the most stable future trend and appears to be the best option. In the next step, using fire flooding technology to develop the reservoir will benefit the most economically. The workflow consisting of "conclusion of reservoir experiment → AHP mathematical modeling → verification of relative permeability of high-temperature oil and water → verification of trial production" is simple and effective. The findings of this study can help to better understand the idea and process of making development plans for sensitive oil and gas fields through reservoir evaluation. Combining experimental data with mathematical modeling can find a balanced combination point in qualitative and quantitative analysis. Whether this combination point is correct can be verified by field engineering practice.

Integrating Physical and Numerical Simulation of Horizontal Well Steam Flooding in a Heavy Oil Reservoir

Abstract LD-N extra-heavy oil reservoir in Bohai Sea is characterized with deep burial and large bottom water. Horizontal-well steam huff “n” puff has been applied, yet due to water coning and serious heat losses, the oil recovery after three cycles turned out to be rather low (1.58%). To find an appropriate follow-up process, this study proposed and analyzed three different flooding schemes: steam flooding, multiple-thermal-fluid flooding, and foam flooding. Scaled 3D physical experiments and corresponding numerical simulation have been conducted to investigate the heating chamber development and fluid production. History match and parametric analyses have been carried out to optimize the well performance and operating conditions. The optimized results include 360 m3/d instantaneous steam injection rate, 1.3–1.4 production-injection ratio, and 13–16 m water avoidance height. In addition, the production well is recommended to be placed above the injection well. These findings provide a useful guidance for the design of thermal recovery schemes and the optimization of production processes for heavy oil reservoirs with bottom water.

A comprehensive investigation of SAGD steam chamber in dual horizontal well pairs: Expansion angel and connection characteristics

The expansion behaviors of the steam chamber play a significant role in the stability of steam-assisted gravity drainage (SAGD). For Long Lake extra-heavy oil reservoir, the 3D SAGD physical model based on similarity criteria is established in this work to investigate the expansion angel and connection characteristics of the steam chamber at varying well-pairs spacing and vertical distance. The results show that expansion angles of the well spacing of 50 m, 75 m, and 100 m are 16.5° and 17.6°, 22.5° and 23.0°, 25.4° and 24.8°, and the sweep efficiency is 96.7%, 90.8%, 78.6%, respectively. The smaller the well spacing between the dual well-pairs, the smaller the final expansion angle of the steam chamber, and the greater development effects. The vertical distances of 3 m have the maximum expansion angles (24.0° and 16.7°), and the highest sweep efficiency (81.6%). The smaller vertical distance of the dual well pair is accompanied by the larger expansion angle, which is beneficial to the development and propagation of steam chambers. The vertical expansion of the steam chamber is concentrated in the early stage of development, and the lateral expansion speed increases after the steam chamber contacts the top of the reservoir. The lateral expansion velocity and width of the steam chamber are the largest (0.36 cm/min and 0.4 cm/min, 20 cm) at the well-pairs spacing of 100 m. The heavy oil recovery factors at varying well-pairs spacing are in turn, 39.4% (50 m), 37.1% (75 m), and 33.7% (100 m). Compared to 6 m and 9 m, the vertical distances of 3 m have the highest ultimate oil recovery, 35.4%. Considering the economy and exploitation effect, the dual well-pairs with 50–75 m spacing and no vertical distance is recommended to promote the successful application of the SAGD technique in heavy oil reservoirs with 20–30 m thickness.

Flow behaviors and residual oil characteristics of water flooding assisted by multi-effect viscosity reducer in extra heavy oil reservoir

Although waterflooding treatment assisted by traditional viscosity reducer yields additional oil recovery, this increments in production sometimes cannot meet the production requirements. To solve this problem, it is necessary to analyze and understand the flow mechanism of heavy oils in the waterflooding process assisted by the viscosity reducer. This study employed an etched glass micro-model to visualize the flow behavior of heavy oils under assistance of a novel multi-functional viscosity reducer with the condition of high temperature and ultra-heavy oil. The water flooding and novel viscosity reducer flooding experiments were carried out, and the state and shape of the remaining oil phase were observed from the global perspective and the microscopic local perspective in the etching micro-glass. Results show that the viscosity reducer solution can not only greatly reduce viscosity of heavy oil but also decrease oil-water interface tension. In the waterflooding process, the continuous oil group and long oil slug are the main characteristics of remaining heavy oil in the reservoir. By waterflooding with the new viscosity-reducer, the remaining oils exist as short slug and droplet, and 3 times wider flooding area for fluid-flow was observed than conventional waterfloodings.

Application of “oil-phase” microbes to enhance oil recovery in extra heavy oil reservoir with high water-cut: A proof-of-concept study

Microbial enhanced oil recovery (MEOR) is an important tertiary recovery technology to recover oil, especially heavy oil, from reservoirs. However, MEOR often fails to achieve satisfactory oil recovery in the field applications because of utilization of unsuitable microorganisms and nutrients. Recent studies proved the existence of microbes inside oil (“oil-phase” microbes) and their potential for application in MEOR. To validate this concept, we isolated microbes from the “oil-phase” of crude oil samples. With them, a synthetic four-member microbial consortium K, was selected to use in an experiment of core flooding, which showed a beneficial capacity for improving oil recovery. Furthermore, the consortium K and nutrients were applied in a field trial of microbial huff and puff in an extra heavy oil recovery. Results demonstrated the incremental cumulative oil production of two high water-cut (99%) shut-in wells reached 1078.8 t and 791.6 t, respectively, with the effective period of 14 months, while the viscosity of heavy oil had significantly declined decreased by 50%. In conclusion, our findings clearly demonstrate that the great potential of a novel methodology to use indigenous “oil-phase” microbes as seedbanks for improving oil recovery in extremely viscous oil reservoirs with high water-cut.

Determination of pores properties in rocks by means of helium-3 NMR: A case study of oil-bearing arkosic conglomerate from North belt of crude oil, Republic of Cuba

The developments of helium-3 nuclear magnetic resonance (NMR) technique to assess porous media properties such as porosity and pore size distribution (PSD) are reported. The method is suitable for use to characterize unconventional extra-heavy oil reservoirs, has a potential in application to tight shales and other unconventional formations, and has several advantages over conventional water NMR. It is based on 3He nuclear magnetic relaxation measurements for different pore loadings and inverse Laplace transform of the data. The relation between different pore types as well as their mean radii are found within the models of spherical, cylindrical and planar pores. The method was applied to study porosity and PSD of rock samples acquired at the North belt of crude oil, Republic of Cuba, the unconventional formation known for its complexity. The obtained pore sizes and porosities are in a good agreement with conventional methods which validates the proposed 3He NMR approach for porous media studies. Advantages of the 3He liquid and gas as probes are discussed.

Two Environmentally Friendly Alkyl-o-Glucoside-Based Formulations for Hole Cleaning during Heavy and Extra-Heavy Oilfield Drilling

Summary The formulation of antiaccretion additives for cleaning the hole in long-range directional or tangential wells in heavy and extraheavy oil reservoirs is considered a technological challenge due to the unconsolidated characteristics of the formations (such as gravel, sand, pea, etc.) as well as the physicochemical properties of the heavy crude oil. In this work, we propose a hole cleaning formulation that can solubilize the asphaltenes present in Mexican heavy crude oil and that is also efficient in eliminating the accretion due to heavy oil fractions. Alkyl-o-glucoside (APG) whose alkyl group has 12 carbons was used as the biosurfactant. The addition of the cosurfactant ethylene glycol butyl ether (EGBE) to the aqueous solution of APG reduced its surface tension. The aqueous APG solutions were able to solubilize the asphaltenes inside the micelles. The addition of EGBE increased the stability of the aspahltenes/APG/water emulsion. The APG/EGBE/Limonene antiaccretion additive proposed in this work for the mobilization of the trapped nonaqueous phase liquid showed a higher cleaning efficiency factor (CEF) than conventional diluents. Higher cleaning efficiency was obtained when the test temperature was increased.

Explosive Behavior of CH4/C2H6/C3H8 Mixtures in the SAGD Process with CO2 Fusion Gases in Extra-Heavy Oil Reservoirs

Explosive Behavior of CH4/C2H6/C3H8 Mixtures in the SAGD Process with CO2 Fusion Gases in Extra-Heavy Oil Reservoirs

Thermo-oxidative characteristics and kinetics of light, heavy, and extra-heavy crude oils using accelerating rate calorimetry

The thermo-oxidative characteristics and kinetics of crude oil directly affected the combustion performance and oil upgrading. This paper brought an in-depth analysis regarding quasi-adiabatic oxidation of crude oil that was still less well-understood. Firstly, the thermo-oxidative characteristics of light, heavy, and extra-heavy oils were studied using accelerating rate calorimetry (ARC). The thermo-oxidative kinetic analysis was then conducted. Particular emphasis was put on the differences into the auto-ignition temperature, exothermic extension of reactions, and kinetic parameters of heavy and extra-heavy oils, with the intent of achieving stable combustion and heavy oil upgrading. The results showed that the light oil encountered heat release triggered by low-temperature oxidation at the reservoir pressure and temperature (7.8 MPa and 95 °C), and its self-ignition temperature was determined to be 100 °C. A continuous heat release was observed in the entire oxidation process, suggesting the air injection might be appropriate for the light oil reservoir. There was no self-exothermic signal at the reservoir pressure and temperature (6.3 MPa and 35 °C) during heavy oil oxidation, and the onset self-exothermic oxidation temperature was found to be 50 °C. Compared with heavy oil, the extra-heavy oil had the obviously higher onset self-exothermic temperature and auto-ignition temperature. This meant that higher ignition temperatures and more lasting ignition time were required when considering in-situ combustion (ISC) of extra-heavy oil. According to the ARC results obtained, we suggested that the near-wellbore areas of the heavy and extra-heavy oil reservoirs were heated up to 120 and 180 °C, respectively. In this scenario, a large amount of heat could be released due to oil oxidation, thereby causing highly efficient upgrading of heavy oil. Additionally, the values of activation energy further confirmed that the heavy oil could be oxidized more easily compared to the extra-heavy oil. The oxidation reactions of heavy oil were less concentration-dependent in comparison with light and extra-heavy oils, indicated by the reaction order. Some new insights derived from this study facilitated achieving rapid and stable combustion, resulting in crude oil upgrading.

Conversion Timing of Following-Up Thermal Recovery Approaches of Post-CHOP for Foamy Extraheavy Oil Reservoirs

The purpose of this study is to determine the optimal conversion timing of follow-up thermal recovery approaches of post-CHOP for foamy extraheavy oil reservoirs. The microscopic visualization experiment and the one-dimensional sand pack experiment are conducted to investigate the influence of temperature on the foamy oil cold production process. According to the experimental results, it can be concluded that the temperature has great influence on foamy oil flow stage during the CHOP process. Therefore, it is necessary to study the optimal conversion timing of follow-up thermal recovery approaches after CHOP for the foamy extraheavy oil reservoir. Based on the analysis of the experimental results, the compositional foamy oil model is established by taking the effect of temperature into consideration. In the numerical model, the conversion timings of different thermal recovery approaches are investigated. The optimal conversion timings for cyclic steam stimulation (CSS) and steam flooding (SF) processes are the moments when the pressure drops to the pseudo-bubble point pressure. For the CSS method, excessive pressure cannot give full play to the production potential of CHOP stage; when the pressure is too low, it lacks enough energy to drive the heated crude oil to the wellbore. For the SF method, high pressure cannot fully release the latent heat of steam, and the content of dissolved gas (which will hinder the heat transfer) in oil phase is higher under high pressure, while the very low pressure leads to relatively high viscosity of crude oil; thus, the performance of the SF process becomes worse. For the SAGD process, the adverse effects of released solution gas in foamy extraheavy oil reservoir outweigh the positive effects. As a result, the CHOP period should be extended as long as possible to obtain a high recovery. In other words, the recovery process should be switched to the SAGD process at a relatively low formation pressure. The findings of this study could help for better understanding of the CHOP and post-CHOP thermal techniques for foamy extraheavy oil reservoirs, and it can provide guidance for reservoir engineers to make better use of the thermal recovery techniques to further improve the recovery performance of foamy extraheavy oil reservoirs.

Screening of waterflooding, hot waterflooding and steam injection for extra heavy crude oil production from Tatarstan oilfield

Thermal enhanced oil recovery techniques, especially steam injection, are the most successful techniques for extra heavy crude oil reservoirs. Steam injection and its variations are based on the decrease in oil viscosity with increasing temperature. The main objective of this study is the development of advanced methods for the production of extra heavy crude oil in the oilfield of the Republic of Tatarstan. The filtration experiment was carried out on a bulk model of non-extracted core under reservoir conditions. The experiment involves the injection of slugs of fresh water, hot water and steam. At the stage of water injection, no oil production was observed while during steam injection recovery factor (RF) achieved 13.4 % indicating that fraction of immobile oil and non-vaporizing residual components is high and needed to be recovered by steam assisted EORs.

Study of Displacement Characteristics of Fire Flooding in Different Viscosity Heavy Oil Reservoirs

A field test in the Xinjiang oilfield in China shows that the viscosity of heavy oil has a certain influence on the combustion dynamics and injection-production performance of fire flooding. The experiment in this study uses a one-dimensional combustion tube to study the temperature, gas composition, and air injection pressure and the production performance of the fire flooding of heavy oil with different viscosities. The results show that the oil viscosities of 1180–22500 mPa·s can achieve stable combustion, and the O2 content of the gas produced during the stable combustion stage is <0.5%. The higher the viscosity of the heavy oil, the higher the temperature in the burned zone and the smaller the range of the temperature increase in the unburned zone. The air injection pressure will increase rapidly until a stable seepage channel is formed, and then, it will drop to a level close to the formation pressure. High-viscosity heavy oil requires a higher air injection pressure and will remain in the high-pressure stage for a longer period of time. Low-viscosity heavy oil has a low water cut in the early stage of fire flooding, a large oil production rate, and a low and stable air–oil ratio. The water cut of high-viscosity heavy oil increases rapidly in the early stage of fire flooding and then decreases gradually, so a good air–oil ratio can only be obtained in the middle and late stages of fire flooding. Thus, fire flooding may be more suitable for application in common heavy oil and some extra heavy oil reservoirs with lower viscosities.

An experimental and numerical simulation study of toe-to-heel air injection for an extra-heavy oil reservoir

ABSTRACT: CAGD is a novel ISC process which inherits the advantages of both ISC and SAGD. It utilizes a horizontal production well near the bottom of reservoir, and a vertical/horizontal injection well in the upper part. After ignition, a combustion zone expands to heat up oil which then mobilizes downward by gravity drainage to the bottom horizontal producer. THAI is a promising type of CAGD that uses a vertical injection well to inject air. This paper examines the efficacy of a THAI process on an extra-heavy oil reservoir in Xinjiang Oilfield, China. A combustion cell was designed based on similarity criterion to carry out the combustion experiment. Then a matching simulation model was established based on the experimental parameters to further explore the applicability of THAI to the targeted reservoir. The results show that ultimate recovery of 81% OOIP was achieved in the THAI experiment. More than 70% of injected oxygen was consumed in the combustion reaction, and the experimental oil was ungraded by 3.8° compared with its original value of 14.8° API. Furthermore, four different THAI well patterns were studied in the numerical model. It is revealed that VIHP got the best development performance for the Fengcheng extra-heavy oil reservoir.

Comparison of Foamy Oil Behaviour between Shallow and Middepth Heavy Oil Reservoirs in the Orinoco Belt

Nowadays, extra heavy oil reservoirs in the Orinoco Heavy-Oil-Belt in Venezuela are exploited via cold production process, which present different production performance in well productivity and primary recovery factor. The purpose of this study is to investigate the causes for such differences with the aspect of foamy oil mechanism. Two typical oil samples were adopted from a shallow reservoir in western Junìn region and a middepth reservoir in eastern Carabobo region in the Belt, respectively. A depletion test was conducted using 1D sand-pack with a visualized microscopic flow observation installation for each of the oil samples under simulated reservoir conditions. The production performance, the foamy oil behaviour, and the oil and gas morphology were recorded in real time during the tests. The results indicated that the shallow heavy oil reservoir in the Belt presents a weaker foamy oil phenomenon when compared with the middepth one; its foamy oil behaviour lasts a shorter duration with a smaller scope, with bigger bubble size and less bubble density. The difference in foamy oil behaviour for those two types of heavy oil reservoir is caused by the difference in reservoir pressure, solution GOR, asphaltene content, etc. Cold production presents obvious features of three stages under the action of strong foamy oil displacement mechanism for the middepth heavy oil reservoir, which could achieve a more favourable production performance. In the contrary, no such obvious production characteristics for the shallow heavy oil reservoir are observed due to weaker foamy oil behaviour, and its primary recovery factor is 9.38 percent point lower than which of the middle heavy oil reservoirs.

Experimental Investigation and Numerical Simulation of Dynamic Characteristics for Multithermal Fluid-Assisted SAGD in Extraheavy Oil Reservoir

AbstractLoss of the vast majority of heat and steam is an unavoidable problem encountered during conventional steam-assisted gravity drainage (SAGD) in extraheavy oil reservoirs. The noncondensate gas coinjection technique of reducing energy consumption and enhancing oil recovery can effectively solve this problem. Aiming at extraheavy oil with a high initial viscosity, the influence of noncondensate gases in multithermal fluids on the physical parameters of extraheavy oil was experimentally studied; the production characteristics and mechanism of multithermal fluid-assisted SAGD were studied through numerical simulation. A comparative investigation of the conventional SAGD and multithermal fluid-assisted SAGD injection schemes was conducted. The characteristics and mechanism of the steam chamber during the production processes were analyzed. The results show that a steam-gas-oil system forms in the steam chamber in the case of multithermal fluids. The steam chamber can be partitioned into four zones, and the flow of the oil mainly occurs in the steam condensation zone and the oil drainage zone. The injected multithermal fluids increase the horizontal expansion of the steam chamber, while the dissolved carbon dioxide reduces the residual oil saturation. Moreover, the nitrogen injection significantly reduces the heat loss and increases the heat utilization for multithermal fluid-assisted SAGD in developing extraheavy oil reservoirs.