Heavy oil reservoirs are generally unconsolidated and easy to produce sand during production 1 . In the late stage of Cyclic Steam Stimulation (CSS), high temperature steam and hot water destroy clay minerals, further aggravate sand production problems, resulting in sand jam, sand burial, pump jam and casing damage, and frequent operations seriously affect the effective production of oil wells. PetroChina has been carrying out steam stimulation for more than 40 years, and has formed a series of sand control technologies in the field of heavy oil thermal recovery. This paper introduces several sand control techniques used in Liaohe and Xinjiang Oilfield and their successful cases. Liaohe and Xinjiang Oilfield is rich in heavy oil resources. The oil types include ordinary heavy oil, extra heavy oil and super heavy oil 2 . In Liaohe Oilfield, they have medium and deep heavy oil with a depth of 600-900m and super deep heavy oil with a depth of 1300-1700m. As the main development method, CSS has entered the late stage of production, more than 9 cycles, and encountered various sanding problems during the production. By using mechanical sand control and chemical sand control measures, the sand path was controlled, and an artificial wellbore was formed in the near-wellbore zone to control the fine silt. Through the discussion in this paper, we can provide a variety of solutions for sanding problems encountered in heavy oil steam handling.

SAGD (steam assisted gravity drainage) has been proven as an effective technology to enhance heavy oil/bitumen recovery. The main shortcoming of this method is its inefficiency, a result of high water and energy consumption. As a solution to SAGD efficiency improvement, we propose the addition of chemicals resulting in higher recovery and reduced steam consumption. The objective of this paper is to screen new generation chemicals as additives and study the mechanisms and optimum injection strategies. This screening was achieved through Hele-Shaw type macroscopic visual experiments. We previously screened a wide variety of chemical additives ( Bruns and Babadagli 2017 , 2018 ) for steam flooding. As a continuation of this work, these chemicals were tested for SAGD conditions using a new visual experimental design where the optimal injection strategies were identified, eventually providing a reference for the selection of chemical additives for field applications. 11 conventional and new generation chemical additives (heptane, biodiesel, DME, LTS-18, Tween 80, Span 80, Novelfroth 190, ionic liquid (BMMMIM BF 4 ), silicon dioxide nanoparticle, DES9, and DES11) were selected based on both their strong thermal stability and enhanced oil recovery capability. The recovery improvement mechanisms for the different chemical additives and different injection strategies were identified through flow characteristics, emulsifying ability, viscosity reduction capability, and wettability alteration. Simultaneously, the mechanisms were studied from a macro perspective via analyzing areal sweep efficiency and microscopic oil displacement efficiency together with observing the images acquired during the process. Three different injection strategies were applied for each chemical: (1) chemicals were injected at the beginning, (2) in the middle, and (3) at the end of the steam injection. The chemical additives played different roles in recovery improvement, and different chemical addition strategies yielded different mechanisms. Heptane exhibited extraordinary characteristics with maximum "steam saving" (34.52%) when the middle injection strategy was applied and maximum ultimate oil recovery (64.75%) was obtained for the end injection strategy due to the ability to reduce the viscosity of heavy oil by dissolving around the chamber edge. Steamflooding with Novelfroth 190 showed an excellent performance for the middle and end injection strategies due to its ability to develop rapid oil drainage "channels". The addition of surfactant LST-18 presented the ability to improve the EOR by forming emulsions. Additionally, the distributions of the steam chamber in the Hele-Shaw cell were different due to the changed flow characteristics when the same chemical additive was injected at different times, thus showing the ability to reduce viscosity and form emulsions with different strengths.

In-situ combustion (ISC) is a promising thermal enhanced oil recovery (EOR) method for heavy oils. However, its field application is still limited due to difficulty in ignition, low combustion efficiency, unstable combustion front, etc. To improve the success rate of ISC process, we investigated the effectiveness of copper-based oil soluble catalyst for catalyzing combustion and in-situ upgrading of heavy oils. High-pressure differential scanning calorimetry (HP-DSC) and TGA were used to investigate the effect of catalyst on the thermochemistry (onset temperature, temperature range of reaction interval, heat effect, etc.) and kinetic parameters of combustion process. A Porous medium thermo-effect cell (PMTEC) was designed to study the catalytic combustion of heavy oil in porous media under air flow. And, a visual combustion tube (VCT) was developed to study the catalytic effect of catalyst on the ISC process, including improving combustion front propagation, in-situ upgrading of heavy oils, and oil recovery. HP-DSC results showed that copper-based oil soluble catalyst significantly shifted the low-temperature oxidation (LTO), transition stage (FD), and high-temperature oxidation (HTO) into lower temperature ranges. Especially for HTO, the end temperature was decreased about 120 °C. It was finished at a narrower temperature region with a higher heat flow, which implies that the combustion efficiency of HTO was greatly improved. TG-DTG data also showed the combustion reaction was transferred into lower temperatures. In addition, from TG-DTG and kinetic data, it can be concluded that the catalyst significantly reduced the activation energy in FD and HTO stage, which thus decreases the reaction barriers between FD and HTO and increases the continuity of reactions between FD and HTO. PEMTC experiments also showed that the ignition temperature of heavy oil combustion in porous media in airflow was decreased about 46 °C by copper-based catalyst. VCT experiments indicated that in the presence of copper-based oil soluble catalyst, combustion front propagate faster, oil recovery was 10% higher than without catalyst, and a deep in-situ oil upgrading was achieved with a significant viscosity reduction (9 times lower) and increase of saturates content (especially alkanes with lower carbon number C 11 -C 17 ). All these results showed that copper-based oil soluble catalyst has a great potential in improving the efficiency of ISC process and in-situ oil upgrading. Its application can help to improve the success rate and wide application of ISC process for heavy oil recovery, which will promote the highly efficient development of heavy oil resources.

Flashing flow is a common phenomenon in many industrial applications and, in steam-assisted gravity drainage (SAGD), it is considered a significant process. Flashing may occur if there is a sudden pressure drop in the production well in SAGD, which is a typical in-situ way to extract heavy oil from tar sands. This may change the expected pressure drop across inflow control devices (ICDs), which are the controllers installed within the production well. Flashing is defined as self-boiling of a liquid due to a reduction of pressure, and it is a complex, multiphase flow phenomenon. The main objectives of the present work are to develop and to validate a multiphase computational model that has the ability to predict the thermo-fluid behaviour of the flow during the flashing process inside ICD nozzles, and to assess its effect on the pressure distribution through ICDs in a predictive way. Our computational model is applied to time-averaged, two-phase, adiabatic, turbulent flows. The new computational model can predict the phase changes between liquid and vapour phases based on mechanical effects (pressure). This is achieved by comparing the local pressure in each computational cell with the local vapour pressure. Considering the thermo-fluid complexity together in one model gives such a simulation the potential to be invaluable for a better understanding of roles of the combined mass transfer and the flashing dynamics during the flashing flow process, and to be applied as an industrial inflow control device to choke back steam for SAGD production system. It may assist in obtaining insight and information where measurements would be difficult. Furthermore, the CFD results can be used to generate compact predictive functions of pressure drop within ICDs, and to investigate the effects of both non-condensable gases and solvents in ICDs performance.

Tight oil reservoirs have become one of the main forces of oil production growth in the USA. Only 3% to 7% of the oil can be recovered under primary depletion. Further improvement in oil recovery in tight oil reservoirs can be achieved by applying gas flooding or huff ‘n’ puff. However, these methods have limitations, especially when dealing with ultra-low permeable formations. Hence, the objective of this study was to discover the limitations of EOR methods in tight formation. A 2D compositional simulation model was used to investigate the limitations of applying gas flooding and huff ‘n’ puff in a tight formation. The results were compared under distinct scenarios and conditions. Distinct values of well spacing were used to identify the optimal well spacing. Different average permeability values were used to study the effect of permeability value on the EOR performance in tight formation. The Simulation Model results showed a potential of applying EOR in tight formation under specific conditions. Well spacing optimization has a significant effect on the gas flooding performance in tight formations. Hence, it is recommended to identify the well spacing before commencing gas flooding or huff ‘n’ puff. This simulation study showed any formation with a permeability less than 0.01 md should not be considered for gas flooding due to gas injectivity issues, long injection time, and long depletion time. Huff ‘n’ puff showed better results and more oil recovery at a permeability less than 0.01 md. Simulation results showed that any formation with a permeability greater than 0.1 md may be considered for gas flooding because of the following reasons: gas flooding showed a better recovery factor compared to the huff ‘n’ puff method; short depletion time was needed to start gas injection; and gas flooding required less injection time and provided long well spacing. This study increases understanding of the EOR factor in a tight formation. The results of the study showed the limitations of the EOR using simulation approaches. Knowing the disadvantages and limitations of EOR in tight formations will lead to improving the efficiency of EOR in tight formations.

The SAGD pilot test in Guantao oil reservoir, Du 84 block Liaohe oil field has achieved good results. But the existence of the top water is harmful to SAGD process. Non-Condensable Gas injection with steam (NCG-SAGD) is a beneficial technique for this kind of reservoir. Gas selection is an important step for NCG-SAGD. Based on the high temperature and high pressure phase-equilibrium experimental devices, the solubility of NCG like CH 4 , CO 2 and N 2 in super-heavy oil has been measured. Also the thermal property of heavy oil saturated with these NCG were tested separately. A numerical simulator is used to forecast the performance of different NCG in this reservoir, and optimize the operating parameters to maximize the effect of NCG additive. After series of experiments, the main results are as follows: The solubility of the three kind of gases is increasing along with the reduction of the temperature and the increase of the pressure. With the rise of the temperature and pressure, the viscosity of the crude saturated with the three kind of gases will reduce, and the density of the crude saturated with the three kind of gases will also decrease. The dissolving capacity in the Guantao oil and the viscosity reduction effect for the three kind of gases are listed as follows from high to low: CH 4 >CO 2 >N 2 . Simulation results shows that the production process for N 2 is the longest because of its good heat insulation property. N 2 is determined as the assistant gas in the SAGD technology according to the demands for top-water reservoir and mechanism of NCG-SAGD technology.

The thermal EOR steam generation projects in Gulf oilfields are on such a large scale that they affect an entire country's economic position. As such, the policies related to oilfield steam generation should be decided at the national level using the cost of the marginal fuel. This paper calculates the steam cost for three methods: 1) once-through steam generator (OTSG) 2) once-through heat recovery steam generator (OT-HRSG) and 3) solar steam generator (SSG). We have created detailed performance and economic models of the steam generation methods and used them to calculate the levelized cost of energy and the Fuel Break Even (FBE). We explore the environmental and economic burdens on the cost of steam generation. The effect of fuel price on the cost of steam is also analyzed with a focus on the marginal fuel price. The analysis shows that the fully burdened steam costs using $6/MMBTU fuel, for OTSG, OT-HRSG, and SSG are $27/ton, $20/ton, and $17/ton, respectively. The FBE for SSG vs. OTSG is $4.95/MMBTU when the OTSG is unburdened and decreases to $2.25/MMBTU when the environmental burden of Carbon Cost is added. The FBE for SSG vs. OT-HRSG is $7.70/MMBTU when burdened with Power Opportunity Cost and $4.50/MMBTU when the additional burdens of Carbon Cost and Water Opportunity Cost are accounted for. Finally, we analyze the limitations of OT-HRSG in an isolated oilfield where the electric:thermal demand necessitiates electricity-matched cogeneration. This limitation along with the steam cost at the marginal fuel price provides the decision-maker with a steam supply curve.

Surface steam injection is the most common enhanced oil recovery (EOR) technology used in heavy oil production. Nevertheless, limits exist due to heat loss for deep reservoirs. In the process of steam injection, adding a certain amount of nitrogen, which can reduce heat loss, maintain formation pressure and expand steam chamber, can effectively improve the development efficiency of steam injection. In this research, high-temperature-pressure pressure/volume/temperature (PVT) measurements and sand pack flooding experiments have been operated for heavy oil of the target reservoir in Bohai Oilfield, China, observing effect of nitrogen on property of heavy oil and steam and nitrogen co-injection on displacement efficiency and optimizing gas-water ratio during the co-injection. The results of PVT measurements indicate that the change of heavy oil viscosity is complex with the varying amount nitrogen dissolved. The reason is that dissolved nitrogen can reduce heavy oil viscosity on one hand; on the other hand, nitrogen can compress oil increasing its viscosity. The viscosity of heavy oil with dissolved nitrogen decreases significantly under low temperature and pressure (80°C, 15MPa), and the maximum viscosity reduction rate is 28%. Along with increase in temperature and pressure (150°C, 25MPa), the viscosity reducing effect becomes worse, especially at 150°C, the viscosity of heavy oil with dissolved nitrogen increases, on the contrary. The results of sand pack flooding experiments reveal that adding nitrogen during stream injection can improve oil displacement efficiency significantly. However, the increase of oil displacement efficiency is different with the varying gas water ratio; therefore, optimizing gas water ratio has a great influence on displacement effect in steam-nitrogen co-injection process. There is an optimal gas water ratio in the process, which is correlated with temperature. For example, the optimal gas water ratio is around 50 and 100 respectively while temperature of 200°C and 300°C. The key of mid-deep heavy oil reservoirs development using steam-nitrogen co-injection technology is gas water ratio optimization, and while optimizing gas water ratio properties of heavy oil, formation conditions and injection conditions, and many other factors should be taken into account. This research provides a direction to choose the optimal gas water ratio in the steam-nitrogen co-injection process.

In rod pump applications around the world heavy oil and sand production is believed to be a dangerous combination. This paper highlights a case study of a heavy oil well in the North Kuwait field where sand production was monitored closely to avoid flow line choke and down hole failures. This case study was used as a pilot for the neighboring wells producing from the same reservoir. In case of wells producing heavy oil with considerable sand production and that undergo cyclic steam stimulation the challenge is often at the end of the production cycle. While the oil is thin and has good viscosity the sand settles itself at the bottom. However, with time as the oil gets colder and thereby heavier, it carries the sand along with it to the surface causing plug in the flow line. This is due to the high viscosity of the oil. This is believed to be the end of production period beyond which it would have been impossible to produce any further even after sand cleanup. Certain operational procedures were established to ensure the integrity of the down-hole equipment and to avoid the failures. It has been observed that by effective sand monitoring it was possible to determine the next injection cycle with more precision. This standardized the injection and production cycle. The flow line choke up problems were completely eliminated as the production period would cease as soon as some sand would begin to appear at the surface. It was possible to establish API gravity cutoff for oil production thus avoiding rod and pump failures. This implementation has been undertaken for the entire field and has shown significant operational efficiency. A pilot was conducted to justify the use of sand production as an indication for the next production cycle for heavy oil well under cyclic steam stimulation.

Solar Enhanced Oil Recovery: Application to Kuwait's Heavy Oil Fields Thermal enhanced oil recovery (EOR) is poised to make a large contribution to Kuwait's oil production and reserves. Over 12 billion barrels of heavy oil in shallow sandstone are known in the Lower Fars in North Kuwait (Oskui et al 2009), and the first phase of thermal EOR targeting 60,000 bopd is now in engineering and construction, with targets established of 270 M bopd and above ( Sanyal 2009 ). Large resources in carbonate formations at the Wafra field in the PZ have responded favorably to pilot thermal EOR ( Barge et al 2009 , Meddaugh et al 2012 ), and large scale production has been planned with first phase of thermal EOR targeting 80,000 bopd (Chevron 2015). Thermal EOR creates huge demands for fuel to make steam, and the cost and availability of that fuel has a very strong impact on the economic viability of the production operation. Kuwait currently experiences gas shortages that are driving LNG imports, and power generation requirements are forecast to rise faster than new domestic gas production. The energy required for these new thermal EOR operations adds greatly to requirements for new fuel supplies in Kuwait Solar steam generation has emerged as a promising large-scale source of energy for thermal EOR operations, with several successful pilot projects now operating in California and the Middle East, and full-field commercial facilities in construction in Oman. Solar EOR replaces gas-fired steam with solar-generated steam, eliminating up to 80% of fuel use. Solar EOR offers large opportunities for reduced production costs and expanded reserves in Kuwait's fields. Kuwait enjoys year-round high levels of solar radiation, allowing solar energy to deliver large reductions in gas used for EOR. Long term solar steam supply without fuel costs will defer "shut-in," extend the economic life and increase ultimate recovery. This creates a triple prize for the Kuwait oil industry: lowered current production costs, expanded current production levels, and increased proven reserves. The Kuwait desert environment poses unique challenges for solar energy systems, however, with levels of wind, sand, dust and heat beyond the experience and capabilities of many existing solar technologies. Special care must be taken in specifying and planning systems for Kuwait oilfield operation. This paper reviews available data on these subjects and the field experience of solar systems operating in harsh environments. We review the technical requirements for successful integration of solar energy into these heavy oil developments, and the key technical challenges. Based on these technical requirements the fraction of solar energy is calculated for various scenarios. The results show that solar EOR can economically replace 75% of the gas required for thermal recovery in Kuwait. All of the 75% savings are delivered by direct solar steam generation, which is the simplest and least-cost approach. The results show that "thermal energy storage" – the molten salt systems which have been used in solar electric power generation is not required and adds additional costs and technical risk.

The steam-foam process is an Enhanced Oil Recovery (EOR) method which aims to improve the performance of a traditional steam drive by using a foaming surfactant. A Canadian thermal project under development in NW Alberta, which will use steam drive to recover extra heavy oil from the Bluesky Reservoir, is a good candidate for the application of steam-foam. A pilot test is planned to evaluate the benefits of the steam-foam process in this reservoir. The steam-foam process is based on the use of a surfactant which, when co-injected with steam into the formation, generates foam. A candidate surfactant for steam-foam should be able to generate stable foam at high temperature, have a good thermal stability, a low rate of adsorption on the rock, and good solubility in brine. An experimental plan was designed to screen for appropriate surfactants to use in the field. Bulk foam height tests at high temperature, thermal degradation tests and static adsorption tests with disaggregated rock were carried out to screen the best surfactant. Two candidate surfactants were chosen based on the results. A pilot test plan was also developed for a proof-of-concept test of the candidate surfactant in the field. The primary success criterion for the test is an increase in the Bottom Hole Pressure (BHP) of the injector well after the start of surfactant injection. Core-flooding tests are currently underway to confirm the performance of the candidate surfactant in the porous medium and determine the value of parameters required for the pilot design. The generation of strong foam in the formation should result in not only a BHP increase in the injector, but also improvement of the Steam to Oil Ratio (SOR) and ultimate recovery. The oil uplift response is dependent on the pattern geometry and geology of the reservoir and may not be observed immediately. However, the BHP increase will be immediately observed provided that strong foam has been generated near the wellbore, and this is the focus of the proof-of-concept test. A more extensive field test is planned for a later date to evaluate SOR improvement and recovery uplift.

At the early phases of EOR developments, small scale pilots are commonly used to obtain information of the EOR field development mechanisms. The lessons learnt from these early pilots are subsequently used to de-risk and improve the full field developments. In initial phases, well and reservoir surveillance plays an important role to increase the understanding of the effectiveness of the EOR processes in the various reservoirs. Well-planned and executed reservoir surveillance has proven in the past to de-risk and optimise production and ultimate recovery from reservoirs significantly. This paper discusses the important field development decisions in Thermal Injection projects, which have been based on well and reservoir surveillance results. A clear methodology is presented to select surveillance strategies dependent on the field development decisions that need to be taken.

During the process of Cyclic Steam Stimulation (CSS) variations in reservoir pressure and temperature occur changing the solubility of reservoir rock minerals in the formation water and therefore during production phase, produced water brings valuable information about dynamic characteristics of reservoir rock and fluid. Its analysis may provide an invaluable means for monitoring the reservoir. This paper describes the process of water analysis where results are interpreted on the basis of the principle that the solubility of minerals varies with change in pressure and temperature. This also shows the importance of water analysis as a key tool for reservoir monitoring in fields undergoing cyclic steam stimulation. Water analysis is also used to optimize impact of produced water on Capex and Opex of oil production as water is required to be handled and disposed without impacting the environment, and is applied as troubleshooting tool to identify well problems and to validate log interpretations. Field examples illustrate application of water analysis in i) mineralogical changes that takes place during CCS operation for reservoir monitoring and impact of steam on clays, ii) determining compatibility of injected steam with the formation water and compatibility of effluent with the formation water of disposal well, iii) surface facility design and water treatment before steam generation, iv) reservoir description and computing fluid saturation using resistivity of formation water and v) troubleshooting well problems, e.g. unanticipated water production because of channeling behind the casing and communication between the layers. Paper discusses the importance of water analysis at each stage of CSS operation and its application in reservoir monitoring and describes field experience with water analysis in the surveillance of a CSS project.

This paper describes an HSE integrated risk assessment performed by a multidisciplinary team for a Steamflood pilot program in a shallow geologically complex multi layered super-giant heavy oil green field in Kuwait, undergoing first phase of development using field tested Cyclic Steam Stimulation (CSS) during first few years then followed by Steamflood (SF). In the first step of HSE integrated risk assessment methodology, the team stablished the most likely production scenarios during CSS and SF for selected well pattern types and sizes, components of surface infrastructure and production operation modes. To determine the safe distance between wells during drilling operations under current conditions, the team performed a consequence analysis. For each scenario the team defined ranges (minimum and maximum) for well production and injection rates, fluid composition, wellhead temperature, gas oil ratios and other key parameters using data and information from reservoir model, pilots and well designs. To account for the lack of data typical in a green field, the team reviewed well blowout failure modes and frequencies from analog heavy oil fields worldwide. Through internal workshops and using data from analogs, the team did the identification, classification, analysis and ranking of hazards and risks, ending up with a risk breakdown structure (RBS) and a risk assessment matrix (RAM). To identify root causes and their mitigation actions the team prepared cause and effect relationships maps and loss causation models for those risks related to HSE. The outcomes of the assessment are a risk register, quantitative risk assessment, detailed reports and guidelines for the Steamflood pilot program as support to prepare HSE procedures. The team identified 66 risks; classified and ranked them using a risk breakdown structure (RBS) and a risk assessment matrix (RAM) and then selected 28 risks with cause and effect relationships with HSE. The cause and effect relationships maps helped defining the 7 most significant groups of risks (likelihood and impact) in the short, medium and long term: 1) Well blowouts, 2) H 2 S & CO 2 , 3) Pattern Type & Size, 4) Heat Management, 5) Non Wanted Fluids & Solids, 6) Reservoir Description and 7) Human Factors. By using loss causation models for each of the seven group of risks, the team established the root causes and risk mitigation options. From the consequence analysis, the conclusion was that 45 meters is the minimum safe distance required between heavy oil wells considering three event scenarios of potential failure cases and the consequences. Finally, to account for the need of critical data related to the most critical HSE risks, the team visualized a Steamflood field test using a small pattern area to reach quickly steam breakthrough and gather a minimum of the needed data in less than 1 year. The HSE integrated risk asssessment methodology presented in this paper is applicable to similar heavy oil green fields to identify potential failure modes associated with well blowouts and other hazards during all phases of thermal operations using data from the subject field or from analogs.

The development of the vast viscous oil resources of Kuwait is considered a very important strategic goal of the country. The first phase of development plans is under implementation to meet a target production of 60 M bopd by a combination of cold flow and cyclic steam stimulation (CSS) followed by steamflood to have optimum recovery from this resource. The thermal development plan for the viscous oil resources, targeting high recovery factor from this resource, is considered to be the first EOR project in Kuwait. The thermal project starts with Cyclic Steam Stimulation followed by steamflood. To optimize the process and maximizing recovery, three pilots have been planned for evaluation of these technologies in this field. A detailed plan was developed to ensure quality surveillance information is obtained to support this pilot performance interpretation. This present paper summarizes the salient features of that surveillance plan and how the planned data can be interpreted, to obtain maximum value from the pilots. First the impact of known reservoir uncertainty parameters was evaluated through simulation studies and field testings, to evaluate their potential to become major risk parameters for the project. A commercial uncertainty analysis software to identify risk factors was used for this study. A comprehensive surveillance plan for evaluation of the potential risk parameters in the pilots was then firmed up, based on available technologies in the industry. The study identifies that an integrated approach is needed involving the completion plan, surveillance options and project goals to optimize learning from the pilots. A realistic surveillance plan, which caters to the different completion plans being evaluated in the pilots, was firmed up. The study also recommends frequency and resolution needed in the surveillance data, for meaningful interpretation of results. A comprehensive surveillance plan in the pilots is considered a key success factor in EOR projects. With increasing demand for fossil fuels in future, evaluation of EOR technologies through pilots would continue to remain a desired option, to reduce project cost and risk. The risk assessment approach elaborated in this study is expected to have relevance in similar EOR projects all over the globe.

SAR Interfeometry (InSAR) provides high precision ground displacement measurements remotely, using Synthetic Aperture Radar (SAR) images acquired from satellites. Thanks to its effective provision of extensive information over wide areas with high acquisition frequency, InSAR monitoring is used routinely in the management of numbers of Enhanced Oil Recovery (EOR) projects. These include heavy oil Cyclic Steam Stimulation (CSS), Steam Flooding (SF) and Steam Assisted Gravity Drainage (SAGD) in Alberta and California. Steam injection recovery is generally operated in shallow reservoirs with low caprock thickness, where measuring the surface effects of pressure variations at depth is extremely useful to assess steam chest expansion and enhance safety. InSAR monitoring provides low-cost effective measurements over large areas and is capable of highlighting zones of excessive pressure or subsidence, as well as to control the integrity and safety of operations and infrastructures. This paper presents an overview of InSAR technologies and their recent enhancements. Some examples of InSAR application in EOR heavy oil projects are reported in order to highlight the advantages offered by these monitoring techniques in reservoir management and recovery optimization.

In recent years, the addition of a hydrocarbon condensate (C4 to C20) to steam operations (such as CSS and SAGD) in heavy oil and bitumen reservoirs has emerged as potential technology to improve not only oil recovery and but also energy efficiency. Shell has extended the idea of solvent addition to a steam drive process, applied it for the first time in the Peace River area in Canada, and obtained evidence of oil uplift in the patterns where solvent was injected. However, piloting this new technology in a brown field had many challenges, especially when evaluating its main economic factors: production increase and solvent recovery. To overcome these challenges, emphasis was put on experimental design, data acquisition and quality, and production surveillance. The pilot conditions were designed to increase the probability of success on the two economic factors aforementioned within a short period of time. The assessment of the pilot required that all production streams (emulsion and casing vent gas) were metered and frequently sampled to measure their respective compositions. Cross calibration of metered and sampled water cuts was essential in obtaining conclusive production uplift data. Automatic proportional samplers were successfully deployed under these challenging conditions to obtain representative samples. Due to the overlap of solvent and bitumen components, special attention was taken to allocate hydrocarbon production into bitumen and solvent. New in-house developed algorithms were tested to accurately calculate this split. The addition of a 4 month concentrated slug of solvent in two steam drive patterns resulted in a significant production uplift when compared to two adjacent patterns with steam-only injection. Solvent recovery is still ongoing and exceeds original expectations. Frequent sampling allowed the detection of several trends, including bitumen composition changes during solvent injection and solvent fractionation in the reservoir.

Cyclic Steam Injection (CSS) has been used in the industry to increase the recovery factor and production rate from heavy oil reservoirs. CSS is multi-cycled steam recovery process with three stages and five operational parameters (injection rate and its duration, soak time, production rate and its duration) in each cycle. Determining the optimal values of the operational variables in each cycle, for the existing reservoir conditions is challenging. The difficulty stems from the fact that these parameters cause significant changes in reservoir fluid flow, reservoir behavior and recovery performance during the project duration. Ability to effectively determine the best values of these parameters is expected to increase the recovery efficiency and the profitability of the project. In practice, the parameters of cyclic steam stimulation are often determined by running limited sensitivity studies on some or all the parameters. Such sensitivity studies are however very limited in scope and cannot explore the entire domain of interest. A more efficient method to estimate the optimal parameters of the CSS is to perform automatic optimization using an effective stochastic optimization algorithm. In this work, we propose the use of stochastic optimization to estimate the parameters of CSS. Three different CSS models were developed with three well types (vertical, horizontal and inclined wells). The operational parameters are extremely interdependent in CSS which has mulitiple drive mechanisms. The need for global search is imperative to find the best operating parameters in each cycle. Covariance Matrix adaption Evolution Strategy (CMA-ES) was used to optimize the operational parameters. The project net present value (NPV) was used as the objective function in the optimization process. Results showed that the NPV can be increased significantly when all the operational variables of CSS are optimized. This signifies the importance of simultaneous optimization of soak time, cycle length and rates. The results also showed that the vertical well model gave a higher NPV than the other two well models. The horizontal well model gave the lowest NPV.

Heavy oil has gained significant attention and importance recently because of a multitude of reasons—growing demand of oil from developing economies, declining availability of easily recoverable or "conventional" oil, and significant advances in required technology. Even though the current estimates of heavy oil in place are three times that of conventional oil, they have only recently become economically viable because of sustained high oil prices. Improved technology has also driven down the recovery risk to minimal levels. The earliest recovery methods for heavy oil were largely cyclic stimulation, with steamflooding gaining acceptance in the 1970s. Despite other thermal and non-thermal recovery methods for heavy oil, steamflooding remains the most widely used technology. Current production by steamfloods alone totals more than 1.1 million BOPD. Previous studies have established how steamfloods are affected by parameters, such as rock properties, oil composition, degree of steam override, sweep efficiency, steam quality, and steam injection rate. However, the capital-intensive nature and low profit margins of the steamfloods mean that each field development decision is crucial and the oil recovery and margins are much more susceptible to uncertainties in oil price, well performance, facility costs, and subsurface parameters. While studies have been performed to corroborate the effect of subsurface parameters and economic uncertainties separately, there has been little advancement in terms of coupling all of them together in one unified study. In this paper, the effects of uncertainties on project net present value (NPV) are studied by coupling numerical reservoir simulation; a design- of-experiments based approach to handle uncertainty, an established economic model, and a commercial optimizing tool to determine the optimal field operating variables.