A Large Scale Thermal Pilot (LSTP) has been in operation in Northern Kuwait in a Heavy Oil Field for some time. Currently, the pilot wells are on Steam flood (SF), after completing two cycles of Cyclic Steam Stimulation (CSS). This paper presents the analysis that led to the improvement of reservoir performance, and the critical learnings from monitoring the steam chamber development from different well completions. The LSTP in the North area of the field consists of 26 vertical production/injection wells, distributed into eight inverted 5-spot patterns. One is a 10-acre area pattern targeting one reservoir unit and the other one is a 5-acre pattern area targeting two commingled reservoir units. A systematic approach for data integration was used by multiple disciplines to improve the thermal recovery of the pilots. This integrated approach led to gaining thermal recovery field experience and learnings for improvement of future commercial development thermal operations in the subject heavy oil field. This paper presents the pilot performance improvements, learnings, and new challenges after analysis of the reservoir performance, including production and injection data, valuable information from dedicated observation wells, impact of completion designs for free-gas and sand management, and supporting systems such as water disposal and water source. Successful pilot performance improvement under the thermal application was promising and it will support the commercial full-scale phase development by implementing the learnings and the integrated approach of all teams, from surface to subsurface, with a shared goal.

A steam flood pilot in unconsolidated sandstone reservoir is being performed for the first time in Kuwait with inverted 5 spot configuration and pattern areas of 5 and 10 acres and a total of 26 wells. Prior to the steam flood, two cyclic steam stimulation (CSS) cycles were applied in all wells. This paper provides a detailed description of the well completions and challenges during CSS and the ongoing steam flood operations. Different designs of well completions were evaluated for injection and production wells. Injection well completion designs were evaluated by comparing actual vs. expected injection rates and review of operational issues. Production well completion designs were evaluated by comparing peak production rates, decline rates and sand issues. Two different injection well completion designs were evaluated. In the 5 acre, the steam injectors target two sand sub layers and hence initially completion were designed with downhole steam splitters but later removed due to injectivity issues. In the 10 acre, steam injectors target a single sand layer using packer less completions. Production wells were completed with 7" case hole perforated with 3.5" completion tubulars and insert sucker rod pump (ISRP). Sand screens were installed in some producers, but 50% of them were removed later due to very sharp production declines. When the screens were pulled out, screens were found completely plugged with debris. The responses from the 2 CSS cycles were very good with average peak well production rates of higher than 100 BOPD. The steam flood pilots have been running for around 6 months and the preliminary results are very encouraging. There is a clear initial response to steam flood, characterized by an overall increase in gross and oil production. The experience and the lessons learned from the CSS and evaluation of initial response of steam flood pilots are very useful in risk identification and mitigation applicable to the commercial phase.

This paper presents a practical method for benchmarking heavy oil fields as a tool for identification of opportunities for total cost and production optimization. The method combines actual data from typical heavy oil fields to define reservoir, well and surface complexity indices, for categorizing a subject field and a total cost breakdown model to map potential risks that could cause total cost to increase, potential project/process delay and poor production performance. The benchmarking process consists of four steps: 1) classification of a subject field using Front End Loading (FEL) and complexity indices that account for: a) reservoir structural, stratigraphic, rock, fluid, energy, static and dynamic complexity, b) well complexity and c) surface processes complexity; 2) selection of analog fields within the range of indices; 3) use of causal maps to identify causes of uncertainty and risks that impact capital expenditures (CAPEX), operational expenditures (OPEX), production losses and cycle time; and 4) a total cost stochastic model is used to generate graphs providing the position of the subject field vs. analogs. A total undiscounted cost breakdown structure provided information on the most critical cost drivers, where significant impact corresponded to OPEX. Causal maps described typical total cost drivers for surface and subsurface. Seven most significant groups of risks are modeled to visualize the impact on cost, production losses, cycle time and health, safety and environment with recommended mitigation actions ranked by cost benefit. A database provides information about cost of production (Capex, Opex) from heavy oil fields undergoing cold production and thermal enhanced oil Recovery well-known heavy oil production areas from Venezuela, Canada, USA and Middle East. Heavy oil fields undergoing thermal enhanced oil recovery indicated typical ranges for Opex from 2 to 22 USD/bbl and Total Cost ranges from 10 to a maximum of 40 $/bbl. A key observation is that cost of fuel and power is the largest single OPEX cost for thermal enhanced recovery accounting for about 50%. Significant production losses are associated to failures due to corrosion and blowouts is the most significant HSE risk. The proposed method helps benchmarking total costs in heavy oil fields, which is a task that requires lot of efforts in researching available reliable sources from technical papers, regulatory agencies, and oil industry. Understanding causes of high cost per barrel and their relationship with uncertainties and risks for heavy oil field, is a formidable tool for multidisciplinary cost optimization as it provides a common language that understood by all disciplines involved.

Kuwait Oil Company (KOC) intends to develop Lower Fars Heavy Oil field on the north of Kuwait that requires steam generation. The Lower Fars Heavy Oil (LFHO) Development Project is targeted at a large heavy oil accumulation of approximately 7 to 15 billion barrels oil-in-place located in a desert area of some 1, 200 km 2 in North Kuwait. The development of this heavy oil resource is important to Kuwait's production strategy. The LFHO reservoir has been partitioned into Well-Blocks; Phase 1 of the LFHO Development Project consists of two such Well-Blocks, which are intended to achieve a target plateau of 60,000 BOPD over a ten-year period from start of operations. This rate will increase after ten years, with future phases ramping up production up to a final plateau of 270,000 BOPD. Reservoir engineering work performed to date indicates that phase 1 areas can best be developed by two or three cycles of cyclic steam stimulation (CSS) followed by continuous steam flood (SF) with steam quality of 55% (wells) to 80% central processing facility (CPF). The steam will be generated by multiple Once-Trough Steam Generators (OTSG) located in a central processing facility (CPF). The Once through steam generation (OTSG) will use for generating steam utilizing treated boiler feed water to improve recovery of hydrocarbon from a reservoir. Integrity process for steam generation equipment considered on Project various stages e.g. equipment selection, design, fabrication, inspection and testing. Integrity process also considered during operation process of OTSG units within a defined integrity operating window (IOW) to establish and maintain a controlled process environment which would enable boiler feed water to be converted into steam in a safe, environmentally responsible manner without upsets and planned shutdown.

Kuwait Oil Company (KOC) is operating two Heavy Oil fields. Field A aims at production by Cyclic Steam Stimulation (CSS), followed by steam flood. Field B envisages primary recovery through cold production, followed by non-thermal Enhanced Oil Recovery (EOR). This requires drilling and completion of large number of wells. Implementing Well, Reservoir and Facilities Management (WRFM) and Smart Field approach will be a key requirement for operation excellence in these fields. Currently both fields have some wells in production, mostly as single isolated wells or wells in 5-acre/ 10-acre spacing. These pilot projects aimed at de-risking the commercial phase, which is to follow in the coming years. These wells are the training ground for young KOC staff to learn how to work in integrated teams using WRFM processes. WRFM processes are tailor-made for KOC's operating environment. These processes include Digital Oil Field based on Exception Based Surveillance (to flag out only those wells and facilities outside of their operating envelope and/or optimization window) and Production System Optimization. This would help to eliminate operational bottlenecks, leading to optimization in manpower to deal with large number of wells. It is expected to be achieved by combining existing best practices of International Oil Companies (IOC) with existing KOC applications, leveraging successful global practices. The paper shall highlight the timeline, activities and organizational changes underway to effect the transformation from existing operation to a larger and more complex development that includes continuous drilling, completion and well intervention (CWI) and facilities installation occurring simultaneously. The implementation of WRFM Processes along with Digital field will achieve the production and operation goals by reducing well, artificial lift, and facility downtime. This innovative production optimization system by enabling efficient decision-making process shall lower the cost per bbl. and reduce down time by implementing automated surveillance workflow.

Heavy oil reservoirs often require thermal enhanced oil recovery (EOR) processes to improve the mobility of the highly viscous oil. When working with steam flooding operations, finding the optimal steam injection rates is very important given the high cost of steam generation and the current low oil price environment. Steam injection and allocation then becomes an exercise of optimizing cost, improving productivity and net present value (NPV). As the field matures, producers are faced with declining oil rates and increasing steam oil ratios (SOR). Operators must work to reduce injection rates on declining groups of wells to maintain a low SOR and free up capacity for newer, more productive groups of wells. Operators also need a strong surveillance program to monitor field operational parameters like SOR, remaining Oil-in-Place (OIP) distribution in the reservoir, steam breakthrough in the producers, temperature surveys in observation wells etc. Using the surveillance data in conjunction with reservoir simulation, operators must determine a go-forward operating strategy for the steam injection process. The proposed steam flood optimization workflow incorporates field surveillance data and numerical simulation, driven by machine learning and AI enabled Algorithms, to predict future steam flood reservoir performance and maximize NPV for the reservoir. The process intelligently determines an optimal current field level and well level injection rates, how long to inject at that rate, how fast to reduce rates on mature wells so that it can be reallocated to newly developed regions of the field. A case study has been performed on a subsection of a Middle Eastern reservoir containing eight vertical injectors and four sets of horizontal producers with laterals landed in multiple reservoir zones. Following just the steam reallocation optimization process, NPV for the section improved by 42.4% with corresponding decrease in cumulative SOR by 24%. However, if workover and alternate wellbore design is considered in the optimization process, the NPV for the section has the potential to be improved by 94.7% with a corresponding decrease in cumulative SOR by 32%. This workflow can be extended and applied to a full field steam injection project.

Selecting the optimum combination of technologies is a critical and challenging activity while conducting the opportunity assessment under high levels of uncertainty in a deep (~9000 feet) extra heavy oil green field transitioning between appraisal and development phases. Low mobility requires enhanced oil recovery to be addressed early in the life of the field, so selected wells can be drilled and completed in selected locations to reduce uncertainty about producibility and flow assurance. This paper presents a practical approach to opportunity assessment based on Front End Loading (FEL) methodology, with three major steps: 1. Evaluation of known data, determination of complexities, uncertainties and risks by benchmarking with selected field analogs, 2. Identification of all potential technology options and 3. Definition of feasible appraisal and development scenarios and a high-level road map including estimates of life cycle cost opportunities for optimization. We found reservoir static complexity medium, well complexity low, and reservoir dynamic complexity high. FEL definition indices for reservoir and well indicated low reservoir definition and acceptable index for wells. These complexity and definition indices were used for conducting benchmarking with three analog fields providing references for risks and ranges of production, recovery and total cost. After multidisciplinary analysis with participation of 35 specialists organized into three clusters (subsurface, well and surface), 100 challenges (72 risks and 28 uncertainties) were identified, analyzed and ranked. Assessment of 36 parameters used for Enhanced Oil Recovery (EOR) screening were assessed from uncertainty perspective with preliminary selection of 7 potential EOR methods. Final integration was achieved with identification of 110 technology options for 30 key decisions, finally selecting best suitable options for 4 potential development chronological scenarios. Results are presented in a cost breakdown structure reflecting the most critical cost drivers, where high percentage corresponds to OPEX affected by identified risks and causal maps describes effects on total costs for subsurface, well and surface. We modeled all significant risks by visualizing its impact on total cost and we defined the mitigation actions ranked by risk adjusted stochastic economics performed as input for decision-making. This paper demonstrates that understanding the root causes of high cost per barrel and their relationship with uncertainties and risks during early stages of a heavy oil field life cycle, provides a common language for multidisciplinary cost optimization, and facilitates communication and involvement of all disciplines.

Data Physics reservoir modeling and optimization was described in detail in a prior paper (SPE-185507) and can be conceptualized as a physics-based model augmented by machine learning. In brief, the production, injection, temperature, steam quality, completion and other engineering data from an active steamflood are continuously assimilated into the Data Physics model using an Ensemble Kalman Filter (EnKF), which is then used to optimize steam injection rates to maximize/minimize multiple objectives such as net present value (NPV), injection cost etc. using large scale evolutionary optimization algorithms. The solutions are low-order and continuous scale, rather than discretized, therefore modeling, forecasting and optimization are significantly faster than traditional simulation. The goal of steamflood modeling and optimization is to determine the optimal spatial and temporal distribution of steam injection that will maximize future recovery and/or field economics. Accurately modeling thermodynamic and fluid flow mechanisms in the wellbore, reservoir layers, and overburden can be prohibitively resource-intensive for operators who instead often default to simple decline curve analysis and operational rules of thumb. Data Physics allows operators to leverage readily-available field data to infer reservoir dynamics from first principles. This paper updates the case study from the previous paper and presents the results of actual implementation of an optimized steam injection plan based on the Data Physics framework. The case study is from a shallow, heavy oil field in the San Joaquin Basin of California, and demonstrates the practical application of Data Physics modeling and the ability to explore future injection plans. The model of the field was fit to historical data in June 2017, after which an optimization was performed and a forward-looking production forecast was established associated with a target plan chosen by the operator. This plan was then implemented in the field over the last year. This paper provides a comparison between the field implementation and the model prediction, which allows for model validation and highlights opportunities for further improvement. For completeness, this paper includes a summary of the modeling and optimization problem and results from the previous paper.

D block is a heavy oil reservoir that was first developed in 1997 with the method of Cyclic Steam Stimulation (CSS). After nearly 20 years’ development, several technical challenges have shown: the reservoir pressure decreased from 7.4MPa to 2.9MPa, and the Steam Oil Ratio (SOR) increase from 2.86 to 3.56. As a result, the traditional CSS method seems to be uneconomic. In view of the problems shown above, CO 2 assisted CSS was tested in this oilfield and has shown great success as follow: The steam injection pressure increased from 5.7 MPa to 6.9 MPa and the SOR decreased from 3.45 to 2.86. Besides the underground success, CO 2 was separated from the associated gas and then reinjected into the reservoir. This process can reduce the emission of CO 2 so that it is both a economic and green method. In addition, according to the field performance, this paper seeks to establish a better understanding of the possible mechanisms involved in the CO 2 assisted CSS.

Kuwait Oil Company (KOC) is developing its shallow heavy oil field using thermal method. Top risk of this project is the cap rock failure. If failure occur, it may lead to the steam leakage, overlying aquifer contamination, ground heave or subsidence and surface collapse. For the monitoring ground deformation caused by cyclic steam stimulation (CSS) and steam flooding (SF) thermal operation in Kuwait, InSAR technology is being considered. Interferometric Synthetic Aperture Radar (InSAR) is a remote sensing technique to measure surface heave and subsidence. First stage of heavy oil thermal development in North Kuwait comprises production from shallow Miocene reservoirs covering an area of roughly 30 square kilometers, by two or three cyclic steam stimulation (CSS) process followed by steam flooding (SF) process. Main reservoirs are the shallow Tertiary un-consolidated sandstone within the measured depth of 650 to 750 feet, sealed off by Up Shale layer that is about 30 FT thick. High pressure and temperature steam will be injected to reservoirs zones, which could result in cap rock breach causing surface heave or subsidence. High-precision and frequent measurements of surface deformation is very important for the study of cap rock integrity. With the advancement of InSAR technology, millimetric precision of ground deformation measurement is possible. The important factors affecting measurement accuracy of ground deformation is Radar microwave length. The most common of microwave is the L band with 24 cm wavelength, the C band with 4-8 cm wavelength and the X band with 2.5-4 cm wavelength. The choice of wavelength influences the precision. However, there are some other factors which have impact on measurement quality such as spatial density of the measurement points, climatic condition, distance between the measurement points and reference points, number and temporal distribution of acquisitions. InSAR technology is expected to provide regular surface deformation maps during heavy oil production to monitor the cap rock integrity and to optimize wells and reservoir management. This technology has many benefits, such as reliability, simplicity, low cost, weather independent, minimal field intervention and ability to acquire at night. The absence of vegetation growth in our field area makes this technology very effective. To increase the frequency of data collection and to improve the accuracy of the deformation maps, satellite ascending and descending images are also used. Use of ascending and decending images helps in calculating the vertical and horizontal deformations from the Line of Sight (LOS) measurmemnts.

Great breakthrough has been made in heavy oil EOR mechanism under water injection at different state. New findings from both experimental and theoretical studies provide strong support for the broad application prospect of steam in heavy oil EOR. In this paper, a series of studies are carried out on productivity of a horizontal well with several vertical steam injectors during the steam-assisted-gravity-drainage (SAGD) process. In this paper, a novel topic is discussed on the effect of steam state on oil productivity during the SAGD process. The injection wells are three parallel vertical wells and the production well is a horizontal well. The numerical method is adopted to reveal the physical aspect mechanisms. Some meaningful conclusions are listed below. (a) The usefulness of superheated steam in heavy oil recovery lays in its chemical reactions with heavy oil and rock minerals. The effect of physical heating on oil recovery efficiency is weak. (b) The oil production rate at the starting stage, from 0 day to 30 day, is oscillating with time due to the fact that the preheating stage is neglected. The connectivity between injectors and producer is poor without a necessary step of preheating. (c) The direction of oil recovery is from well-bottom of the injector to the well-head and then to the places between the injectors. (d) Chemical reactions may play an important role in oil recovery efficiency if the final recovery efficiency by injecting steam with higher steam quality is several order of magnitude than that by injecting steam with lower steam quality. We carried out the pilot study on the effect of steam state on heavy oil EOR during the SAGD process with several vertical injectors. More importantly, the pilot study conducted in this paper provide the very basis for the application of superheated steam for oil companies and following academic research in the field.

In thermal heavy-oil production, steam is injected to reduce oil viscosity and promote the less viscous oil flowing to the production wells. Steam injectivity and its conformance in the reservoir greatly impacts oil production and project economics. It is found that hydraulic dilation stimulation of heavy-oil reservoirs before steam injection can create a large and targeted stimulated reservoir volume for the steam to contact the heavy-oil phase. As a result, steam injectivity increases and steam conformance improves. These eventually translate to increased oil production and reduced steam/oil ratio, which has been proven in hundreds of wells worldwide. This paper describes relevant fundamental mechanisms and field performance. As a major novelty, the hydraulic stimulation avoids fracturing the reservoir, but seeks to cause dilation. If the reservoir is fractured, a linear conduit is created. Steam can easily break through to neighbouring wells and the steam conformance is poor. When dilation takes place, however, additional pore space is created in the rock matrix. This results in truly volumetric stimulation, which is helpful to increase the steam injectivity while ideal thermal conformance is also achieved. This paper illustrates these theoretical bases and their resultant positive field performance in assisting thermal heavy-oil production.

Sand control and sand management require a rigorous assessment of several contributing factors including the sand facies variation, fluid composition, near-wellbore velocities, interaction of the sand control with other completion tools and operational practices. A multivariate approach or risk analysis is required to consider the relative role of each parameter in the overall design for reliable and robust sand control. This paper introduces a qualitative risk factor model for this purpose. In this research, a series of Sand Retention Tests (SRT) was conducted, and results were used to formulate a set of design criteria for slotted liners. The proposed criteria specify both the slot width and density for different operational conditions and different classes of Particle Size Distribution (PSD) for the McMurray oil sands. The goal is to provide a qualitative rationale for choosing the best liner design that keeps the produced sand and skin within an acceptable level. The test is performed at several flow rates to account for different operational conditions for Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) wells. A Traffic Light System (TLS) is adopted for presenting the design criteria in which the red and green colors are used to indicate, respectively, unacceptable and acceptable design concerning sanding and plugging. Yellow color in the TLS is also used to indicate marginal design. Testing results indicate the liner performance is affected by the near-wellbore flow velocities, geochemical composition of the produced water, PSD of the formation sand and fines content, and composition of formation clays. For low near-wellbore velocities and typical produced water composition, conservatively designed narrow slots show a similar performance compared to somewhat wider slots. However, high fluid flow velocities or unfavorable water composition results in excessive plugging of the pore space near the screen leading to significant pressure drops for narrow slots. The new design criteria suggest at low flow rates, slot widths up to three and half times of the mean grain size will result in minimal sand production. At elevated flow rates, however, this range shrinks to somewhere between one and a half to three times the mean grain size. This paper presents novel design criteria for slotted liners using the results of multi-slot coupons in SRT testing, which is deemed to be more realistic compared to the single-slot coupon experiments in the previous tests. The new design criteria consider not only certain points on the PSD curve (e.g., D50 or D70) but also the shape of the PSD curve, water cut, and gas oil ratio and other parameters.

The cost per barrel is higher for Heavy Oil developments, and particularly thermal developments than for Conventional. Specific attention needs to be paid to the cost of Heavy Oil developments to ensure economic viability. The current cost basis for the heavy oil project shows that energy costs constitute some 45% of Unit Technical Cost and more than 65% of the OPEX per barrel. An OPEX cost improvement plan has been conceptualized to reduce the cost per barrel. Hence, the improvement plan focusses on Alternative Energy sources for steam generation. In addition to the cost optimization, those initiatives will contribute heavily in achieving HH the Emir of Kuwait vision to cover 15% of Kuwait’s peak load with renewable energy by 2030". Based on current field development plans a feasibility study was carried out to determine the maximum practical and economic fraction of energy that can be contributed by renewables in heavy oil development. The bulk of the work was executed developing a model to study the supply-demand balance, as well as the gas prices ranges within the alternative energy solutions are viable. To optimize the fuel gas consumptions two options were studied by utilizing the alternative energy solutions (solar steam and cogenerations) to generate steam instead of conventional boilers. On the power optimization side the study focused on the solar photovoltaic and wind energy. The lowest cost solution is to use direct solar steam and allow the steam injection at a variable rate - this may require some upgrades to allow fully- automatic flow control throughout the steam distribution system. With this method (and a typical weather year) solar fractions of approximately up to 40% may be possible. It may be possible to increase this further if the requirements for minimum steam flow in the steam distribution network can be reduced. With the use of thermal storage, the solar fraction can be increased to approximately 60-80%, however steam from storage is likely to cost significantly more than direct steam, especially as direct molten-salt coupled with oilfield- quality water has not yet been proven commercially. As renewable power alone will not be able to meet the full demand of Heavy Oil field development, hence the utilization of cogeneration will be a feasible solution in order to supply the required steam demands in addition to solar and also to supply the required power in addition to solar PV. The redundant power generated by the cogeneration may be supplied to the Electrical Grid. The economics analysis illustrates that all renewable options considered have positive NPV. The economics for both PV and wind are robust, where maximum deployment is advised, subject to grid connection constraints. For solar steam, the economics are partially affected by the once-through steam generators (OTSG) CAPEX already spent, but still show positive NPV. Anticipated costs reductions for solar steam technology as a consequence of greater deployment of the technology over the next few years could further improve the NPV. Including the cogeneration, solar steam and less conventional steam generators in the future projects will maximize the NPV of the heavy oil.

A thermal steam project has been successfully implemented in a Petroleum Development Oman (PDO) field in the South of Oman. The thermal project developed the crest of the field which has mainly formation A. The thermal response has been favorable as witnessed by the incremental oil recovery. The steam flood is now planned to be expanded further to the South where it will encounter the same formation as currently developed at the crest & to the North where it will encounter two new formations (B & C). The new formations have limited field data on sand production; therefore a sand prediction evaluation for both cold & thermal production conditions is required for these new formations. In this paper we describe the analysis of the sand control potential and the selection process of the sand control technology. The assessment of the potential for sand production and the requirement for sand control was based on a combination of a) actual field data such as sand production, well performance & completion data; and b) a sand prediction model for the hot and cold operating production conditions utilizing rock-mechanical data. In addition, core sieve analysis data were used to determine the Particle Size Distribution (PSD), which was used to select the sand control type and screen slot width. The sand evaluation study demonstrated that for formation A has only the probability of transient sand failure under hot operation conditions. The wells will therefore be completed without sand control. On the other hand, formations B & C have a risk of catastrophic sand failure under both cold and hot operation conditions. A completion with thermally compliant sand control is a must for formation B. In case of formation C the selection of sand control is challenging as the sand distribution shows a high percentage of fines. In this case sand control is obtained through selective perforation, excluding the sand prone intervals. The impact of blanking the high GR intervals on inflow is expected to be low as the average the permeability for these intervals is low. The implementation of the selected Stand Alone Screens for sand control in formation B will be the first thermal application of these screens in PDO.

Cyclic steam stimulation is one of the important ways to develop heavy oil. In the past research, saturated steam and superheated steam were mainly used as injected fluids. With the advancement of technology, supercritical water cyclic steam stimulation began to receive more and more attention. Thermodynamic oil recovery is the main way of heavy oil development, and supercritical water as a displacement medium for thermodynamic oil recovery has high pressure, high thermal enthalpy value and low density which makes it easy to spread in formation. At the same time, supercritical water also has some special properties, its polarity will reverse under high temperature and high pressure, which is beneficial to the mutual solubility of supercritical water and crude oil, increasing the efficiency of oil displacement. In this paper, a cyclic steam stimulation model is presented for estimating recovery factors and production rates of different injection fluids, and the corresponding parameters are derived by a pilot field test. Firstly, a steam stimulation model using different injection fluids is proposed based on the properties of supercritical water, saturated and superheated steam. Secondly, according to the established model, the effect of the state of injected water on production rate and recovery factor of cyclic steam stimulation was studied. Thirdly, using supercritical water as the displacement medium, the effect of injection rate on production rate and recovery rate of cyclic steam stimulation was studied. Finally, the optimal production rate is obtained by analyzing the results. Results show that: (a) Supercritical water can better heat the formation during steam stimulation than saturated and superheated steam. (b) Supercritical water has better injection capacity than saturated and superheated steam. (c) Cumulative oil production when injecting supercritical water is greater than the injection of saturated steam and superheated steam. (d) Cumulative oil production of supercritical water injection increases as injection rate rises. (e) The higher the injection rate is, the higher the production rate at the same production time.

The use of catalysts has been considered as an effective method to improve the efficiency of in-situ combustion (ISC) process for heavy oil recovery. In this work, we present a new small-scale combustion tube to quickly and effectively evaluate the effect of catalysts on ISC process. Different oil-soluble metal-based catalysts were evaluated for ISC process for heavy oil recovery using this small-scale combustion tube. These experiments can provide the information about the stability of combustion front, oil recovery, and in-situ oil upgrading information. Using this device, ISC process was successfully simulated. It turned out that the ISC process itself can effectively improve heavy oil recovery up to about 70 % and simultaneously achieve an in-situ oil upgrading evidenced by a significant viscosity reduction and an API increase. The presence of oil-soluble iron-based, nickel-based and copper-based catalysts can achieve a further oil upgrading to the level of medium oil from heavy oil with a more significant reduction in the content of resins and asphaltenes. However, the in-situ oil upgrading in ISC process yielded by iron-based and nickel-based catalysts at the expense of an unstable combustion front and a lower oil recovery (about 10 % lower than that without catalysts). The presence of copper-based catalysts not only achieved a further oil upgrading, but also improved the stability of combustion front and yielded a higher oil recovery (about 5 % higher than that without catalysts). The obtained results indicated that oil-soluble copper-based catalyst has a great potential for improving the efficiency of ISC processes for heavy oil recovery. The new small-scale combustion tube was proven to have the ability for a fast and effective evaluation of the influence of catalysts on ISC processes.

Steam assisted gravity drainage (SAGD) is widely applied in the exploitation of oil sand reservoirs, however, the development process is affected by complex geological conditions, wherein the interlayer has a great impact. Specifically, it has a great influence on heat and mass transfer of steam and on the effective flow of crude oil. For this reason, the characteristics of steam chamber and the production performance were investigated in detail to clarify the influence mechanism of interlayer. In this paper, based on the reservoir parameters of Long Lake oil sands, a series of numerical simulations were conducted to study the characteristics of SAGD process with interlayers. First of all, the numerical simulation method was used to study the influence mechanism of interlayer on heat and mass transfer. Then, based on the above analysis, we reclassified the production stages. Finally, we completed a series of numerical simulations with different parameters of interlayer to determine the influence level of main factors. The results of temperature profile show that the upper zone of the interlayer is mainly heated by heat conduction, whereas the area far from the interlayer is heated by the coupling effect of heat conduction and heat convection, hence, the steam chamber above the interlayer develops slower and the steam chamber in the area without interlayer develops faster. At the same time, it can be seen from the oil saturation profile that a dead oil zone is formed near the formation just above the interlayer. In addition, the production stage is no longer the classic "three-stage", due to the interlayer, the oil production rate is fluctuating, appearing peak production. Finally, we summarized the regular of the influence of each parameters and determined the main parameters, we considered the location, size, porosity, permeability, and thermal conductivity of interlayer comprehensively, the results show that the influence of thermal conductivity is smaller than other parameters.

Steam channeling is an important factor affecting the steam flooding, for thin heavy oil reservoirs, the steam overriding in the vertical direction is not as severe as the thick heavy oil reservoir, and often can form a regular shape of the steam front which can directly reflect the extent of steam overriding. it also can determine the steam swept volume, steam breakthrough time. Therefore, the study of steam front is of great significance. In this paper, a series of works are conducted to study the characteristics of steam front of horizontal steam flooding. Firstly, the equation of steam front and the equation of motion are established. Then, coupled with energy conservation equation and mass conservation equation, a comprehensive model is established. The model is solved with method of characteristics and the predicted results are compared against field data and previous models. The results show that: (a). The new model is applicable to predict different shapes of the steam front according to the production conditions. (b). The comparison between experimental results and model results showed that this new model can predict the steam front well. (c). The comparison of steam front among different shapes indicated that linear-shape was the best, followed by the concave-shape, and the convex-shape was the worst, usually causing severe steam overriding and the severity will increase over time, the development effect can be improved by forming a proper shape of steam front.

Heavy oil is an important part of unconventional resources. Many great breakthroughs have been made in heavy oil EOR mechanism of thermal methods. With the unprecedented development of technology, Super-critical Water Coupled with Toe-point Injection Technique is entering people’s view. Compared with previous thermal methods, the reservoir can be heated to a higher temperature by injecting supercritical water, obtaining a larger heated radius. Meanwhile, toe-point injection could abate the problem of early channeling and unequal steam absorption caused by heel injection in extremely long horizontal wellbore or reservoir of serious heterogeneity, which results in a higher recovery rate. In this paper, a novel topic is discussed on the effect of different parameters on oil productivity during the single horizontal well production process, using discrete horizontal well model. The recovery process is completed through a single horizontal well--the supercritical water is injected into the reservoir through the tubing, while oil is produced to the surface through the annulus. Some meaningful conclusions are listed below. (a) Under the same production policy, the recovery ratios of supercritical water are generally higher than those of steam, indicating that, besides its chemical reactions with heavy oil and rock minerals and fracture initiation ability, the effect of physical properties (high pressure and high temperature) on oil recovery efficiency also play an important role in the usefulness of supercritical steam in heavy oil recovery. (b) The relative well height in the reservoir has significant influence on the production performance, whose impact varies as the production methods change. Consequently, the optimum well position ns under diverse production methods are different. (c) The direction of oil recovery is from toe point to the heel point. The matching between well height and the growth of steam chamber and water puddle decides the production performance.