Steam-oil Ratio Research Articles

Productivity analysis by insulation design of well with vacuum insulated tubing in SAGD process

This study aims to design insulation and demonstrate its performance on the vertical section of a well in a steam-assisted gravity drainage (SAGD) process. Utilizing the reservoir characteristics of the Athabasca oil sands in Canada, we analyzed oil productivity and derived optimal operating conditions through a multi-objective optimization algorithm. For the simulation, the well's vertical section was insulated with 0.006 W/m‧°C, the thermal conductivity of vacuum insulated tubing (VIT), exhibiting high insulation efficiency. The results indicated that cumulative production increased by up to 20.24%, and production efficiency improved. Additionally, sensitivity analysis using response surface methodology (RSM) revealed that the injection bottom-hole pressure (inj_BHP) was the most significant factor in the insulated well design when parameters varied. A multi-objective optimization using particle swarm optimization (PSO) was conducted to determine the optimal operating conditions, aiming to maximize cumulative oil production and minimize the cumulative steam-oil ratio (cSOR). The optimization resulted in a 39.8% improvement in cumulative oil production and an 88.19% reduction in cSOR, compared to the non-insulation scenario. The findings of this study are anticipated to serve as a guideline for wellbore insulation design in SAGD processes.

AN EXPERIMENTAL STUDY ON THE USE OF SEDIMENTATION COMPOSITIONS DURING STEAM INJECTION

At present time, many oil fields, especially in historically developed areas of The experience of developing deposits of high-viscosity oils (HVO) and natural bitumen has shown that thermal methods are the most promising technologies. Of the entire arsenal of thermal methods, areal steam injection and cyclic-steam stimulation have become the most widespread.When choosing an effective thermal impact technology, it is necessary to take into account the peculiarities of the geological and physical parameters of deposits and the factors involved in oil recovery. An effective technology should be based on the use of the main most important factors that increase oil recovery.One example of areal steam injection is the underground-surface method of developing the Yarega area of the Yaregskoef ield. With this technology, steam is pumped from the surface through vertical wells. Oil production is carried out in the underground galleries of the oil sheds.Twenty years of practice and geophysical studies of steam injection wells have revealed a number of factors that prevent uniform heating of the reservoir over the entire thickness and efficient use of coolant energy. It turned out that the injected steam is mainly concentrated in the bed zone of the formation. In this case, the formation does not warm up evenly in thickness. The heterogeneity of the reservoir (tectonic disturbances, cracks every 20-25 m) does not allow the creation of steam pressure up to 1,6 MPa along the contour of the developed areas in order to involve the inclined block. At design pressures, steam breaks into mine workings and gently descending production wells are observed.The experimental studies described in this work are aimed at finding alignment of the intake profile of steam injection wells and redistribution of coolant in a remote reservoir zone. The results of the application of sedimentation compositions in bulk reservoir models under various thermobaric conditions of steam injection are presented. As a result of injection of solutions of iron sulfate, sodium carbonate and calcium chloride, insoluble sediments were formed in the rock, which led to a decrease in permeability during water vapor filtration. The experimental study was performed on a bulk reservoir model using natural core grinding, as well as drilled and extracted core samples from wells of the Yaregskoe field. The use of sedimentation compositions in steam injection wells in the future may contribute to the involvement of rock sections in the development by redistributing the steam flow, which in turn will increase the oil recovery coefficient and reduce the steam-oil ratio.

SAGD Trial in Omani Heavy Oil Field Overcomes Suboptimal Conditions

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215943, “Short Spacing, Lower Viscosity, and Suboptimal Operating Conditions SAGD Trial in Mukhaizna Heavy Oil Field,” by Buthaina S. Al Yahmadi, Rawaa M. Al Aamri, and Walaa S. Al Suqri, Oxy, et al. The paper has not been peer reviewed. _ Mukhaizna is a heavy oil field in southern Oman. It is a multistacked reservoir that has been producing under steamflood since 2007. The main sandstone reservoirs were developed using horizontal producers in each target zone supported by vertical injectors. Although most of the patterns are thermally mature, a few areas still are awaiting steamflood response. To mature these areas, a steam-assisted gravity drainage (SAGD) pilot was evaluated, customized, and implemented using existing patterns and well configurations. Mukhaizna Field The Mukhaizna heavy oil field contains viscous, low-gravity (14–18 °API) crude oil in the shallow Permian-age sands of the Gharif formation. Porosity is very good (25–35%), as is permeability (1,000–10,000 md). The Gharif formation consists of upper, middle, and lower reservoirs. Different injector and producer configurations were evaluated to ensure good production. Because a shale barrier clearly was present in the Gharif formation in most of the area but absent elsewhere, the development of this formation was affected. After evaluation of various pattern-configuration options, a development plan was based on three vertical injectors and three horizontal producers per pattern. Thermal development of the field with steam injection began in July 2007. Steamflood maturity has been inconsistent across the field. Various methods of optimizing steam-injection volumes or steam reshuffling in the offset injectors in some patterns were attempted in order to accelerate thermal maturity, but some horizontal producers were still cold with low inflow. To solve this, a pilot-project area with two stacked horizontal producers was evaluated for SAGD potential. These two producers targeted the same zone, Upper Gharif 2A, in one of the best reservoirs in the field. This area was supported by a horizontal injector that had strong communication with the lower producer, but because of misalignment between the horizontal injector and the upper producer, the upper producer was cold, with its progressive cavity pump at pumpoff condition. To evaluate this SAGD trial and predict performance, two analogs were reviewed to compare reservoir properties and parameters. The first analog, Jackfish1, is considered a successful SAGD project, exceeding 90% of its nameplate capacity since first steam. The second analog is Xinjiang oil field, which was not a successful SAGD project, with a steam/oil ratio (SOR) reaching 4.3. This SAGD trial aimed to enhance the oil production of cold patterns with two stacked wells while gaining an understanding of the potential challenges and opportunities of applying SAGD in the existing well configurations at Mukhaizna. The upper horizontal well was converted to a steam injector with an insulated tubing completion. The nearby horizontal injector was kept at the same injection rate to avoid any changes in operating conditions around the SAGD trial.

A new pressure control scheme on steam‐assisted gravity drainage for heavy oil production

AbstractAs one the most important recovery mechanisms of steam‐assisted gravity drainage (SAGD), gravity drainage is largely dependent on the inclination angle of the steam chamber edge. The existence of solution‐gas causes an ellipsoid‐shaped chamber that has small inclination angle at the bottom, which leads to inefficient gravity drainage and slows down oil production. To address this problem, this study proposes a new scheme, variable‐pressure SAGD (VP‐SAGD). It is basically a SAGD process, at certain stages of which pressure surge is induced by controlling the operating conditions so that the shape of steam chamber can be altered. This leads to a larger slip angle in the steam chamber at the bottom and more efficient heat transport between hot steam and crude oil. Results show that VP‐SAGD is able to increase oil recovery by up to 20% and decrease cumulative steam–oil ratio (cSOR) by up to 7%. Its special oil extraction mechanisms include swabbing effect, enlarged inclination angle of steam chamber boundary at the bottom, and enhanced heat transfer. Particularly, the inclination angle is increased by up to 40%. In addition, a lower producer bottom‐hole pressure (BHP) during pressure drawdown leads to a better production incremental in later stages. The optimal timing for pressure surge is the middle stage of steam chamber growth. The lower the producer BHP decrease, the better the yield increase. Moreover, The VP‐SAGD strategy works better in heavy oil reservoirs with a permeability of k = 0.5–10 Darcy or solution gas content of greater than 2%.

Data-driven analysis of using flow control devices and extended reach wells on SAGD well performance

The industry's current trend to reduce Capital Expenditures (CapEx) and to minimize the environmental impacts has led to drilling long lateral wells and developing key innovative tools like Flow Control Devices (FCDs). This study analyzed the relative performance of various FCD deployments using data from major Steam-Assisted Gravity Drainage (SAGD) projects in Western Canada, spanning from 1997 to mid-2022. The goal is to investigate the impact of FCD deployment and increasing the lateral length on SAGD well performance in terms of boosting oil produciton and lowering cumulative Steam Oil Ratio (cSOR).This paper utilizes a normalization technique to evaluate the production history of wells, considering geological and operational parameters. Following our confidential conversations with experts in the industry, wells exceeding 850 m in lateral lengths are labeled as “long”, while those below 850 m are labeled as “short”. Eventually, normalized oil production and cSOR for all wells are analyzed. A comparison is made between short and long wells that are completed or retrofitted with FCDs, giving an insight into the role of completion design on the relative performance of SAGD wells.Reservoir thickness and reservoir quality are assessed for each well using contour maps and Gamma Ray (GR) log images. These images are digitized using image processing codes developed in our study. On average, across all projects, wells equipped with FCDs produced up to 52% more normalized oil than those without FCDs, and cSOR decreased to 18%. Long wells, on average, had lateral lengths 38% greater than short wells and produced 18% more normalized oil than all short wells. When comparing long wells with and without FCDs, the normalized oil production is improved by up to 36%, and cSOR is lowered by up to 17%. Furthermore, comparing long wells with FCDs to short wells without FCDs reveals that the normalized oil production is improved by up to 96%, and cSOR is lowered by up to 26%. The results highlight the synergistic benefits of combining longer wells with FCDs to improve normalized oil production and cSOR. The historical production analysis show that installing FCDs is the key enabler and an innovative strategy to increase productivity, reduce cSOR, and make longer wells more productive.The findings indicate that FCDs might increase oil production and decrease cSOR for SAGD well-pad developments, allowing operators to reduce Greenhouse Gas (GHG) emissions intensity. The findings may be used to examine paradigm shifts in the development of heavy oil deposits as technology advances while keeping the project economics into account.

A practical workflow to design inflow control devices in SAGD projects to increase production and lower fresh water usage

This paper discusses the significance of inflow control devices (ICDs) in steam-assisted gravity drainage (SAGD) operations and their impact on well performance in different reservoir heterogeneities and qualities. The study focuses on investigating the specifications of ICD design using a numerical flow simulation model and flow rate versus pressure data obtained from a flow-loop experiment. The key advantage of employing flow-loop experiment data in the simulation would be a physics-based mechanistic model rather than using empirical correlations.The research collects core analysis data from three wells and particle size distribution (PSD) data from four wells in the same location. Permeability estimation is conducted for each PSD using a previously developed correlation. These data and other real data are used to construct the reservoir model, and the performance of liner deployed (LD) ICDs is compared by assigning flow-loop data to the simulation.By employing a relatively conservative production approach with subcooling between 10 °C and 15 °C, the cases with LDICDs demonstrate higher oil production rates, improved steam conformance, and lower cumulative steam oil ratios (cSOR) compared to the case without LDICDs. However, in a relatively challenging production scenario with subcooling between 1 °C and 5 °C, the case without ICDs cannot be simulated at the desired subcooling temperature and the cases with LDICDs improved the well productivity. LDICD#1 is identified in both scenarios as the best case due to its enhanced steam conformance and higher oil production rate.Compared to the case without ICDs, using LDICD#1 at higher subcooling temperatures leads to a 17 % increase in oil production rate, while reducing cSOR and natural gas usage by 8 % and 10 % respectively. Similarly, at lower subcooling temperatures, the case with LDICD#1 shows a 21 % increase in oil production rate and reductions of 12 % and 17 % in cSOR and consumed natural gas respectively, compared to the case without ICDs.The findings highlight the effectiveness of LDICDs at various subcooling levels and their potential application in SAGD projects to reduce freshwater usage and greenhouse gas emissions. Completion and production engineers can benefit from a better understanding of relative production performance to develop more effective operational designs.

Integration of machine learning and data analysis for the SAGD production performance with infill wells

AbstractThere have been numerous studies on predicting the production performance of the steam assisted gravity drainage (SAGD) process by data‐driven models with different machine learning algorithms since their introduction into industry. Similar efforts on SAGD infill wells, nevertheless, remain rare for this advanced alteration in improving the classical SAGD performance. On the other hand, predictive tools to optimize an infill well start time is useful in maximizing bitumen production and minimizing its costs. In this paper, a series of SAGD infill well models are constructed with selected ranges of operational conditions. Three SAGD infill well production performance indicators, namely, an increased ratio (), a total steam–oil ratio (SORtotal), and a stolen ratio () for each SAGD infill well, are calculated based on simulated infill well cases and control models. Five different machine learning algorithms (an artificial neural network [ANN] algorithm, three gradient boosting decision tree [GBDT] algorithms, and a support vector machine [SVM] algorithm) are trained, tested, and evaluated for their effectiveness in predicting those three indicators as output parameters, given seven SAGD relevant parameters as input parameters. Comparisons of different data sets show that the ANN is the best in predicting all three performance indicators under different infill well start times among all the above machine learning algorithms, while the GBDT algorithms have a better ability to learn a variation trend in the SAGD infill well performance.

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.

Thermal energy storage biogel with good biodegradability for solar energy powered heavy oil recovery

For cleaner production of heavy oil with lower fossil fuel consumptions, solar thermal enhanced oil recovery (Solar TEOR) technologies are increasingly researched nowadays. However, the intermittency of solar radiation and inferior energy efficiency of steam flooding restricted industrial applications of Solar TEOR methods in oilfield. In this work, the eutectic NaCl–KCl and graphite were loaded into the biomass gelling matrix (crosslinked methylcellulose network) through supramolecular interactions. Then, a thermal energy storage biogel (NaCl–KCl)@G/MC with high thermal conductivity (2.06 W m−1·K−1), latent heat storage capacity (melting enthalpy: 112.4 J g−1 at 352.4 °C) and thermal reliability (melting enthalpy retention up to 94.4% after 30 cycles), was synthesized for improving the continuousness of solar thermal supply and energy efficiency of steam flooding. From the experimental results, the proposed oil recovery method — solar powered steam flooding in daytime + the thermal-storage biogel heated N2 flooding in nighttime — can meet the all-weather 24/7 production of heavy oil and improve energy efficiency (oil-steam ratio and thermal efficiency up to 0.56 and 62.1%). With (NaCl–KCl)@G/MC biogel assistance, energy consumption of oil production was decreased from 153.1 J·(mL oil)−1 to 9.9 J·(mL oil)−1 as the cost reduction of 19.8% in comparison with intermittent solar steaming. This study offers a candidate design to achieve a continuous thermal recovery of heavy oil entirely powered by solar energy, promoting the solar thermal technologies in oil industry operations.

Highly thermoconductive biogel for enhancing thermal efficiency and soil self-remediation in heavy oil recovery

The thermal recovery of heavy oil is an energy-intensive process with serious soil contamination due to its low energy efficiency and refractory petrolic/metallic pollutants emissions. In this work, a thermoconductive lignin-based hydrogel CaLS-CTS/h-BN was designed and synthesized for thermal energy conservation and soil self-remediation in thermal recovery, as a profile-control and oil-displacement agent. From experimental results, with the assistance of CaLS-CTS/h-BN gel, the thermal efficiency and cumulative oil-steam ratio of steam flooding were enlarged by 260% and 293% (up to 41.3% and 0.36), as input energy declined (reduction ratio 84.8%) from 15.08 kJ·(mL oil)−1 to 2.29 kJ·(mL oil)−1, through improving heating profile and strengthening heat transfer. Meanwhile, the rapid biodegradation of CaLS-CTS/h-BN biogel alleviated the formation damage and preserved subsequent productivity. On the other hand, after application of CaLS-CTS/h-BN gel, the natural degradation ratio of petroleum pollutants in soil was increased by 254% up to 46% due to the bio-stimulation and bio-ventilation effect of the biogel. Heavy metal content of oilfield soil was reduced by 35.8 wt% (from 17.3 g·(kg soil)−1 to 10.9 g·(kg soil)−1) with multiple heavy metal contaminants (including Cd, Cr, Cu, Zn, Mn, Pb and Fe) chelated and immobilized by the biogel. This study offered a green adjuvant agent for cleaner production of heavy oil.

Laboratory experiment and field application of chemical assisted steam flooding

ABSTRACT There are serious problems such as steam channeling and low oil-steam ratio when it comes to steam flooding. In order to improve its performance and to enhance oil recovery, foam agents and oil displacement agents are used to enhance the sweep efficiency and the displacement efficiency in steam flooding process. The design, development, and syntheses of high-performance low-cost foam agent and oil displacement agent were put forward in this paper. Evaluation experiment results showed excellent foaming performance and the high-temperature resistance of the foam agent. In addition, good interfacial performance and thermal stability of the oil displacement agent were also observed. The developed system was able to achieve ultra-low interfacial tension under steam flooding conditions. Laboratory experiments of chemical assisted steam flooding showed that the injection of the high-temperature foam agents and oil displacement agents totally enhanced oil recovery of 11.67%. Chemical assisted steam flooding field test has also been carried out in Gudao Zhongerbei Block of Shengli Oilfield. By June 2020, the cumulative oil production in the pilot area was 4.02 × 105 t with the reserve recovery percent of 54.6%, the enhanced oil production was 3.56 × 105 t and the enhanced oil recovery factor was 19.3%.

The impact of permeability barriers on steam-solvent coinjection – A mechanistic study using a physical model

Coinjection of steam and condensate has been studied for improving the energy efficiency of steam-assisted gravity drainage (SAGD) as solvent-assisted SAGD or SA-SAGD. However, it is not well understood how tortuous hydraulic paths under heterogeneous permeability can influence the compositional and thermal flow characteristics in SA-SAGD. We addressed this question by performing an experiment of the coinjection of steam and condensate for bitumen recovery. This paper discusses the experimental results and gives our mechanistic analysis of how the tortuous hydraulic paths affected the thermal and compositional flow and the properties of the produced bitumen in the experiment.The physical model was a cylindrical pressure vessel with a diameter of 0.425 m and a length of 1.2 m, which was filled with unconsolidated sands. Two shale plates were horizontally installed above the well pair at different elevations so that they could represent permeability barriers to cause tortuous flow paths during the SA-SAGD experiment. The porosity and permeability of the sandpack was 0.34 and 5.6 D, respectively. Initially, the oil and water saturations were 95% and 5%, respectively.After preheating for 1 day, a mixture of 98.2 mol% steam and 2.8 mol% condensate was injected at 3500 kPa for 4 days (35 cm3/min of steam, cold water equivalent). The injection and production histories along with the real-time temperature distribution were recorded during the experiment. Produced oil samples were frequently taken and analyzed for density and asphaltene content. After the experiment, the sandpack was excavated and sampled from different locations to analyze the saturation and asphaltene content of the remaining oil. The experimental results in this paper were compared with the previous SAGD and SA-SAGD experiments that used the same experimental set up with a homogeneous sandpack.Results showed that, in comparison to the homogeneous SAGD case, SA-SAGD was able to lower the cumulative steam-oil ratio (SOR) by a factor of two to three even in the presence of shale plates. Analysis of the temperature profiles indicated that the steam chamber vertically expanded from the lower part to the upper part through tortuous paths at lower temperatures. An emerging steam chamber above the shale plates occurred by convective heat from the injection well through lower-temperature flow paths between shale plates, involving light to intermediate solvent components that enabled the steam chamber to expand away from the injection well. This highlights the important role of volatile solvent components in the growth of a steam chamber in SA-SAGD under heterogeneity. The produced bitumen density in this research was closer to the original bitumen than in the homogeneous SA-SAGD case because the bitumen dilution and the solvent retention increased by the tortuous flow regime resulted in efficient drainage of oil at lower temperature.

A New Analytical Model for Predicting Steam-Assisted Gravity-Drainage Performance in the Plateau and Decline Stages

Summary Analytical models have been widely used to study the steam-assisted gravity-drainage (SAGD) process. Existing analytical models for this process either underperform or are limited in their applicability. In this paper, a new analytical model is developed to address these shortcomings. The new model consists of three major components. First, an equation for predicting oil production rate during the plateau stage was developed. This equation allows for permeability anisotropy in the reservoir, which is neglected in the majority of existing analytical models. Second, a novel and concise equation for calculating oil production rate during the decline stage was derived. This equation for the first time provides a general relationship between oil production rate during the decline stage and the properties of the reservoir together with key operating conditions and simultaneously mitigates the shortcomings of the majority of existing models (e.g., inapplicable in the decline stage of the SAGD process). Third, new correlations representing heat loss from the steam chamber to the overburden and heat transfer to oil-undepleted zone ahead of the chamber interface were derived; new predictive equations for estimating steam/oil ratio (SOR) in the plateau and decline stages of SAGD were obtained. The new model has been validated against a 2D scaled laboratory experiment and a set of field data. The results of this validation show that the new model predicts the oil production rate and SOR over the lifetime of an SAGD operation (excluding the short steam rise period) reasonably well. Predictions from the new model were also compared with several existing analytical models: The new model provided a closer match to actual measurements than other models. This robust model is grounded in more physics and incorporates reservoir geology and well operating conditions. It enables better understanding of the SAGD process and significantly improves the prediction of SAGD performance. Hence, it can be used to design new SAGD projects, predict existing projects, and optimize existing projects.

Experimental Study on Improvement Mechanism of Electric Heating-Assisted Cyclic Steam Stimulation of Horizontal Well

To resolve the issues of the high porous medium flow resistance, low oil production rate, high oil decline rate, and low oil recovery factor for the cyclic steam stimulation (CSS) of horizontal wells in heavy oil reservoirs, the CSS method assisted by the electric heating (E-CSS) of horizontal wells was proposed in this study. Combining the heat from electric heating and steam during E-CSS, the analytical model of formation temperature rise was established for the three phases of electric-assisted CSS (i.e., injection, soaking, production), and physical experiments were carried out to compare the performance of conventional CSS and E-CSS. The experimental results were used to validate the analytical model and reveal the impact of the key electric heating mechanism on the horizontal CSS performance. Meanwhile, the typical well model was used to forecast the E-CSS potential. The results indicate that electric heating can achieve uniform heating in the steam injection phase, maintain heating around the wellbore in the soak phase, and reduce flow resistance and enhance oil output in the production phase. Forecasts of the typical well model indicate that electric heating can enhance the oil recovery factor by 9.4% and the oil-steam ratio from 0.14 to 0.23, implying a significant application potential in heavy oil reservoirs developed by horizontal CSS.

Improving mining development modelling based on the thermal methods

Introduction. The problem of oil recovery growth and oil reserves management improvement in active oil fields is growing annually. It is possible to increase oil recovery and improve oil reserves management by introducing the thermal methods of oil production. This method was applied at the Yarega oil field. The thermal mining development technology is currently being implemented at the Yarega territory on an industrial scale. Lyael territory is developed by SAGD technology. Heat capacity and thermal conductivity are crucial characteristics of rocks. Reference books and databases lack reliable data on sedimentary rocks thermal properties. The traditional experimental base of thermal petrophysics cannot provide representative information on the thermal properties of rocks, considering rock heterogeneity and anisotropy, various fluid saturation, and pressure and temperature fluctuations. Results. According to special petrophysical studies of the Yarega highly viscous oil field core, ambiguity has been revealed in the thermal properties of rocks, including anisotropy, heat capacity and thermal conductivity. When applying laboratory results in modeling, divergence in oil production and cumulative steam oil ratio can reach 60%. Main ambiguity arising in the course of thermal mine development modeling has been identified. The ambiguity is associated with the account of production for a well, a large number of underground wells, and low reservoir pressure (lower than atmospheric pressure). These problems are successfully solved by specialists of the Yarega field, who maintain highly viscous oil development. At low reservoir pressures, the simulator encounters errors on low pressure values during well operation. Conclusions. At the Yarega field, permanent geological and technological model is currently actively being implemented. It is aimed at solving technological problems of ambiguity in the development of highly viscous oil by thermal methods using advanced software.

Simulation and evaluation on enhanced oil recovery for steam huff and puff during the later phase in heavy oil Reservoir—A case study of block G in Liaohe oilfield, China

Steam huff and puff has become one of the most widely used technologies to enhance oil recovery during the early phase in heavy oil reservoirs. However, when the development entered in the later phase gradually, the production performance had characteristics with low oil-to-steam ratio and the oil recovery is generally 20–30%. Predecessors usually study a certain follow-up method for a block, and the well pattern is very regular. For the oilfield in the later phase of steam huff and puff, there was a lack of systematic comparison and evaluation with different follow-up methods under irregular well patterns. In this paper, the heavy oil reservoir in block G of Liaohe oilfield was taken as an example. In view of the complex geological conditions and irregular well pattern, the follow-up developing strategies, steam flooding (SF), steam assisted gravity drainage (SAGD) and fire flooding (FF) were compared and evaluated by numerical simulation. A model with seven components and four reactions (used in FF) was established by using STARS module of CMG software. A variety of combined well patterns with vertical and horizontal wells were designed for comparing the production performance. In total, two cases of SF, three cases of SAGD, and two cases of FF were simulated and the oil recovery were studied. The results indicated that these follow-up development methods can enhance oil recovery in different degrees. The combined well pattern with vertical and horizontal wells had a better production performance than that of only vertical wells. In the study, the performance of FF with the horizontal well was the best (oil recovery was 31.7% in the 20th year; cumulative air oil ratio was 3973 m3/m3; final oil recovery was 54.6%), while the SAGD with one horizontal well was the worst (oil recovery was 15.3% in the 20th year; cumulative steam oil ratio was 17.7 t/m3; final oil recovery was 32.6%). Compared with SAGD and FF, the performance of SF was not the best and far from the worst (oil recovery was 40.3% in the 20th year; cumulative steam oil ratio was 12.7 t/m3; final oil recovery was 40.3%). The results show that when the well pattern conditions are complex, the number of wells is large, and the formation is heterogeneous, the SAGD of the vertical and horizontal well combination is obviously affected by the inter well interference. Meanwhile, SAGD production has certain delay and high water cut. It seems that the production performance of SF is not affected by horizontal wells, and the water cut is high. FF with horizontal wells has obvious production performance and can find more uniform formation temperature rise and stable water cut between 0.5 and 0.7.

Optimization of the Steam Alternating Solvent Process Using Pareto-Based Multi-Objective Evolutionary Algorithms

Abstract Steam alternating solvent (SAS) process has been proposed as a more environmentally friendly alternative to traditional steam-based processes for heavy oil production. It consists of injecting steam and a non-condensable gas (solvent) alternatively to reduce the oil viscosity. However, optimizing multiple process design (decision) variables is not trivial since multiple conflicting objectives (i.e., maximize the recovery factor, reduce steam–oil ratio) must be considered. Three different multi-objective evolutionary algorithms (MOEAs) are employed to identify a set of Pareto-optimal operational parameters. A multi-objective optimization (MOO) workflow is developed: first, a 2D reservoir model is constructed based on the Fort McMurray formation. Second, a sensitivity analysis is performed to identify the most impactful decision parameters. Third, two response surface (proxy) models and three different MOEAs are employed and compared. This paper is the first to compare different MOEAs for optimizing a wide range of operational parameters for the SAS process. The results show that if more steam is injected, extending the steam cycle duration is preferable. Conversely, if more solvent is injected, it is recommended to start with injecting a solvent with high propane concentrations over short cycles and switch to lower propane concentrations over long cycles near the end.

Investigation of Horizontal Well for Cyclic Steam-Solvent Stimulation to Escalate Heavy Oil Production

Indonesia's oil reserves that have been exploited on a large scale are light oil because the recovery technique is much easier than the heavy oil. Generally, heavy oil has a high viscosity compared to light oil. In most cases, to reduce high oil viscosity (greater than 50 cp) using steam injection. Cyclic steam stimulation (CSS) is one of processes that commercially developed by numerous oil company to producing of heavy oil reservoir. The CSS can apply in vertical well or horizontal well. The research of CSS in horizontal well is still limited reported in the literature. On the other hand, the horizontal well has drainage area more wide compared with vertical well. In this study, solvent addition in cyclic steam stimulation will be tested with reservoir simulation. The steam was injected on the well, after that soaking time and the last was producing of liquid fluid reservoir. As the result, the oil production increases 3 times higher compared to without solvent. Furthermore, cumulative steam oil ratio (CSOR) and cumulative energy oil ratio (CEOS) decrease about 50% and 16%, respectively. In here, effect of solvent added in the steam, the steam distribution and drainage area wider.

A Novel Analytical Model for Steam Chamber Rise in Steam-Assisted Gravity Drainage

Summary Fluid flow and heat transfer during steam chamber rise (ramp up) in the steam-assisted gravity-drainage (SAGD) process is very complex. The majority of existing analytical models fail to capture the physics of this stage and their estimations of oil production and steam/oil ratio (SOR) may be questionable. This paper presents a new analytical model to predict the advancing velocity of the steam chamber in the vertical direction, correlations of oil production rate and SOR, and the evolution of chamber profile during this stage using material/energy conservation and gravity-drainage theory. The new analytical model was validated against field observations, laboratory measurements, and numerical simulations. Results showed that the new analytical model not only successfully predicted oil production rate and SOR with improved reliability and accuracy but also for the first time properly predicted the chamber profiles with time during the ramp up stage. Using this model, impacts of the key parameters were investigated. The investigation revealed that permeability anisotropy had a considerable impact on development of the chamber profile. Under the constant horizontal permeability condition, the smaller the ratio of vertical to horizontal permeability, the shorter and wider the chamber profile. A small subcool control strategy could boost oil production and steam chamber growth, which is consistent with experiments and field data. Investigation also found that increasing the distance between injector and producer was beneficial for oil production. However, changing this distance may cause some operating/performance/economic problems and so should be approached cautiously. This paper represents the first time that the evolution of chamber profiles in the ramp up stage was characterized mathematically. Useful guidance for operators on improving ramp up performance can be extracted directly from this model.

Development of a Generalized Experimental Methodology for Investigating the Role of Steam Quality on Steamflooding Performance

Summary For steamflooding processes, steam quality plays a crucial role because it affects enhanced oil recovery mechanisms and production performance. Many numerical simulations have been performed on the role of steam quality. However, few studies have evaluated the role of steam quality on steamflooding performance by experimental measurements because of the lack of a generalized experimental methodology to accurately generate and measure steam with different qualities under reservoir conditions. The objective of this study is to propose a generalized experimental methodology for investigating the role of steam quality on steamflooding performance. A steam quality controlling box was newly designed and fabricated to generate steam with different qualities, and its reliability was verified by a novel steam quality measurement system together with a developed theoretical method. Then, a series of experiments were conducted by our designed 1D and 2D sandpack models to evaluate the steamflooding performance under different steam qualities. The results showed that the developed methodology could accurately generate and measure steam with different steam qualities. The maximum errors between desired, measured, and calculated steam qualities were 4.39% under the experimental conditions in this study. The steam quality substantially affected the steamflooding performance. A higher steam quality led to a lower water cut, a lower maximum pressure difference between the inlet and outlet of the sandpack model, a lower water/oil ratio (WOR), a lower steam/oil ratio (SOR), a higher oil recovery, and a higher oil production rate. However, there is an optimal value of steam quality from the view of heat efficiency in this study. The oil recoveries of 2D steamflooding experiments increased from 36.30 to 45.02% when the steam quality increased from 0 to 0.8. However, the optimal steam quality of 0.6 had the maximum heat efficiency at 3.16×10−5 kJ−1. This research contributes to a better understanding of steam quality on steamflooding performance and also provides a generalized methodology for other steam injection processes.