Steam properties such as steam pressure and steam quality are critical parameters to form integrated steam chamber and control steam consumption cost during SAGD process. However, steam property variation along steam injection well was not well understood yet. In this paper, a model describing steam flow behavior in steam injection wellbore was built and solved; accordingly steam property variation along steam injection wellbore can be calculated. In our model, both vertical and horizontal wellbores were further divided into several segments. Mass, momentum and energy balance equations have been applied to steam flow inside each segment. During the derivation of these equations, a void fraction correlation that is based on flow-pattern-independent drift-flux model was applied to describe steam flow in a non-uniform manner. This model was validated by several sets of published field data and a series of general cases were studied to investigate the steam property variation inside wellbore. The computational results indicated that steam property distribution along vertical and horizontal wellbore portions have similar characteristics: steam pressure and steam quality tend to decrease along with wellbore trajectory in both vertical and horizontal wellbore portions during SAGD process; With the increase of steam injection pressure, steam quality decreases faster; with the increase of steam quality during injection, steam pressure decreases faster; With the increase of steam injection rate, steam pressure decrease faster while steam quality decrease slower. For horizontal wellbore, the increase of reservoir permeability tends to slow down the steam pressure decrease but accelerates steam quality deterioration; the increase of oil viscosity tends to slow down the steam quality deterioration but accelerate steam pressure decrease. The results from this study show the effects of steam properties varying along wellbore trajectory under different steam injection conditions and can be used as a design guidance to optimize the steam injection practice in SAGD process.

There has been a large number of laboratory tests run in the past, looking at recovery of heavy oil by chemical flooding (polymer, surfactant and SP or ASP systems). These tests have all shown a potential for significant incremental oil recovery from chemical injection compared to water alone. The higher oil recovery was generally achieved under high pressure gradients that were generated during chemical injection. As such, the mechanism proposed in all of these studies is that of water channel blockage and improved sweep from chemical injection. In actual reservoir applications of chemical flooding, the impact of these water pathway blockages may be much less important than what is observed in the linear laboratory scale tests, so the actual mechanisms of chemical flooding in real systems may not be properly represented. In this project, an experimental investigation is performed using a 2D visual Hele-Shaw cell, to visualize production mechanisms during the chemical flooding process. The 2D nature of the system allows for an understanding of whether chemicals sweep incremental oil from along the same channels as the pre-formed water or if new displacement channels are formed. The flow of a fluid in such models also represents flow without any pore-scale trapping, so observations can be made regarding whether trapping and fluid re-diversion are the only ways that these chemicals can yield improved oil recovery, or if simple alteration of the mobility ratio without additional trapping will already lead to incremental oil.

The use of horizontal wells for injection and production to help maximise the sweep efficiency and economic recovery; especially for recovery of viscous oil in offshore environments. Flow control devices (FCDs) are readily used to control the flow along the well in conventional recovery operations leading to improved recovery efficiency. The benefits of polymer flooding and FCDs has been well demonstrated, however the combination of the two technologies has yet to be fully realised. The cause of FCDs not being as utilised in polymer injection application is due to the severe degradation of the polymer through devices. This paper provides a workflow used to determine the benefits of a well planned and executed polymer injection complemented by the optimum flow control strategy. The main focus will be on demonstrating the relative weights in the objective function of optimising the sweep efficiency with the cost of reduced polymer quality. This workflow will allow a number of strategies to be studied, such as the impact of well types, well placement, well lengths, FCDs and polymer viscosities. The impact of polymer viscosity reduction in an injector well with FCDs is of particular interest. Hence the trade-off of the polymer degradation and the ability to get the required polymer quantity in the various segments of the well will be described. The feasibility of polymer flooding with flow control is a viable alternative for classical enhanced oil recovery (EOR) but the decision whether or not to implement it has to be based on prudent analysis and decision making process. Hence the study highlights the importance of understanding uncertainties with control as well as those associated with reservoir and geology.

Mature heavy oilfields in the Peruvian jungle have been produced for more than 40 years with natural strong water drive assisted with ESPs. Primary recovery factor with cold production methods reached 15% in average, and ultimate recovery will arrive to 17% at economic limit of 98% water cut. Traditional completion systems in mature Peruvian oilfields include both some deviated wells with ESPs inmmediatly above 7" liner hanger, and horizontal wells completed open hole; thus, selective production is not possible and water flow eventually breakthrough to the well while reducing relative permeability to oil and oil rates. This paper proposes a methodology to evaluate cold production strategies to look for "new oil" in mature fields either by redefining completion technology alternatives or by applying new development schemes, which focus on delaying gas or water breakthrough, and avoiding by-pass oil. Based on experience and application in many oilfields in the region, some cold production strategies were identified as critical to bring new life to brown fields such as active inflow control devices (AICD), horizontal and multilateral wells from one slot and production optimization with real-time monitoring. Many successful applications of AICDs with horizontal wells were reported worldwide, and some recent projects in sub-Andean basins have recorded successful results in Colombia and Ecuador (10% to 30% increase in cummulative oil production and 10% to 50% decrease in water production, during the first two years). In addition, preliminary numerical simulation studies for mature heavy oilfields in Peru shows 10% increase in cummulative oil production and 15% decrease in water production during the first two years. On the other hand, automation and real-time monitoring of brown fields came up with a considerable reduction of downtime and production deferment (in between 65% and 85%) due to a proper planning of well interventions, as well as, an improved operational efficiency of equipment. Active inflow control devices (AICD) allows equalizing the influx of oil and unwanted fluids (water or gas) by creating additional backpressure in zones that produces at higher rates. Heavy oil (higher viscosity fluid) takes a relatively non-restrictive path while water or gas (lower viscosity fluid) flows through a tortuous path causing a decrease in its flow rate. On the other hand, both horizontal and multilateral wells increase drainage area, sweep efficiency, well productivity and recovery factors while delaying water breakthrough. Finally, the transformation of a mature field into a digital oilfield means not only downtime and reduction of oil production deferment, but also, a better well production performance, protection of equipment and maximization of operational efficiency.

Foam has been used to improve the efficiency of steam injection since the late 1970s and the process has been applied successfully in several fields in particular in California but interest sagged at the end of the 1990s due to low oil prices and little activity took place for several years. The topic has however become more popular in the recent years due to higher oil prices. Foam is generated by the introduction of surfactant along with the steam into the reservoir and reduces its mobility, thus improving the sweep efficiency and reducing heat losses. There has been no review of the process since the classical work by Hirasaki ( Hirasaki 1989 ) and this paper proposes to remedy the situation and present a state of the art of the process. The paper will revisit the field tests from the 1980 and then focus on the recent developments in the laboratory where researchers are attempting to develop new workflows and improved surfactant formulations for better performances; in the field with some recent pilot tests; and in terms of reservoir simulations. This paper will allow engineers to get a complete and up to date understanding of the characteristics and limitations of the process and some guidance as to whether foam could help improve the performances of their steam injection projects.

Liaohe Oilfield is the largest heavy-oil production base in China, and In-situ combustion with Gravity is one of the emerging new technologies applied in the thermal developed reservoir of Liaohe Oilfield, and this paper mainly introduce four important technologies researched for the development of In-situ combustion with Gravity, including and the ignition technology with the special introduction of the small-diameter removable igniter which could meet the needs of reutilized ignition, the separate air-injection technology with the function of igniting different layers, the horizontal production technology with the integrated tube and the temperature prediction model for horizontal production well, as well as the lifting technology with the high erosion-resistance performance. In-situ Combustion with Gravity Pilot Test is being conducted in the Shu1-38-32 Block of Liaohe Oilfield, and the Pilot Test shows that all the technologies researched for the In-situ combustion with Gravity have reached the requirements designed in the scheme, especially the ignition temperature monitored in the air-injection well could reach the 527°C, which is the critical condition for the High-temperature Oxidation Combustion. The In-situ Combustion with Gravity shows a great potential to be a nonconventional EOR process, and the experience achieved by the pilot test of In-situ Combustion with Gravity in Liaohe Oilfield will definitely provide references for the development of heavy oil.

In various parts of the world, heavy oil projects use high temperatures in order to support the oil production. Most of these projects are still on-going after several years of high temperature well exposure, while others have been suspended due to operational and environmental issues. The well integrity time span should extend itself beyond the field estimated operational date. These wells (observation, productions or abandoned) are highly susceptible to leaks due to cement degradation resulting from thermo-chemical-mechanical loads. Therefore, successful further development of heavy oil reservoirs requires a closer look at the assessment of well integrity and its prediction for extensive periods of time. During the life of the well, the casing-cement-rock system is experiencing, as a secondary problem, a cumulative damage. This could explain the sustained casing pressure that appears after years of good well integrity. Long time exposure of the well to several loads as well as cyclic load changes may affect the well response due to a rather unexplored degradation of the mechanical, chemical and thermal parameters. In this case, the typical loading mechanisms are thermal, associated with superimposed chemical and mechanical loads. A large number of studies has been conducted to investigate the very complex chemical degradation process of Portland cement systems, which is influenced by temperature, pressure, chemical reactions and their products and, more important, time. A literature review of various investigations on well degradation processes has shown that most of the experiments are time-constrained, and therefore the well integrity is limited to the interval in which results extrapolation is possible. Cement retrogression has also been investigated and research led to recommendations of adding silica flour to the Portland cement. The least investigated aspects of the cements are their cyclic resistance to variable loads. This paper will critically analyze the various existing well integrity concepts and point out the future need for research to improve the prediction of well integrity. The results of the work show that the major unknowns are long term properties of the downhole environment like casing, cement, and the interaction between casing-cement-formation. Moreover, a simple, yet attention-grabbing experimental investigation has been carried out on several cement samples with different properties by simulating the cement layer associated to the surface casing of a well exposed to temperature variations. Due to the shallow depths, the cementing of the surface casing may yield specific well integrity issues generated by low slurry density requirements, original low temperature environment, high fluid-formation temperature differences, all leading to potential problems related to health, safety and environmental standards worldwide (e.g. aquifers damage, operational risk, etc.).

Understanding reservoir structures is necessary when using autonomous inflow control devices (AICDs). Without a sound knowledge of nearby structures or manmade elements, such as injectors, production from heavy oil applications or any advanced completion may fall short of operator expectations. This paper provides several field examples to help illustrate the importance of understanding reservoir structures when using AICDs. The approach of this study is based on using a near wellbore (NWB) hydraulic simulator coupled with a reservoir simulator to capture holistically the completion/reservoir effects and interaction. With this approach, the production of unwanted fluids is delayed. When unwanted fluids do eventually break through, the AICD can greatly reduce the negative effects of the unwanted fluids on well production. Usually, the unwanted fluids are water and/or gas. Unwanted water is typically (but not limited to) coning or fingering from bottom or edge water drive or from nearby injectors. Gas is coned or fingered downward from the gas cap. Results show that, without understanding the structure and nearby anomalies of the reservoir, operators utilizing ICDs or AICDs can exacerbate the production of unwanted fluids. Field examples are derived primarily from heavy oil well completions designed for multiple operators in Columbia, Ecuador, Argentina, Brazil, Mexico, Alaska, and Canada over the last eight year period. Typically, completion design must change as more information is gathered about the reservoir. Structural maps are often difficult to obtain, however importing the reservoir model into the design reservoir simulator model adds value. However, the field simulator grid blocks can be too large, creating a lack of definition along the horizontal well, and log data may not be included. This paper presents some simple methodologies in generating the most effective design possible from provided data. Establishing clear communication, gathering as much data as possible (including structural maps), and using proper models and simulators are key to optimizing advanced completion designs, particularly when utilizing AICDs in heavy oil.

Solvent Assisted-Steam Flooding (SA-SF) was developed to address the environmental and economic challenges associated with steam generation. The solvent composition can greatly affect its interaction with both the asphaltenes present in the oil as well as the clays in the reservoir; therefore solvent selection plays a major role in the process. This study explores the wettability alteration mechanism of oil recovery, and how the solvent selection impacts its performance. Five experiments were conducted; two chemical flooding (E1 and E2), one steam flooding (E3) and two SA-SF (E4 and E5) experiments. The solvents tested were n-hexane (E1 and E4) and a commercial solvent (CS) (E2 and E5). The wettability alteration caused by the different enhanced oil recovery methods was established through contact angle measurements. The asphaltene and clay content of the produced oil was determined using standard methods. The residual oil content was measured by washing the postmortem samples with toluene, an asphaltene soluble solvent capable of removing all the oil present in the rock. The oil recovery rate was used to measure the performance of each experiment. Although all experiments had a final wettability that is considered oil-wet, they varied among each other. Experiment E4 showed the least oil-wet surface, while E5 showed the most. At the same time E4 yielded the highest oil recovery of the SA-SF experiments. Lowest clay content and highest asphaltene content was observed in the produced oil of E5, while the opposite was seen in E4. Asphaltene-clay-water interactions in the pores affect the wettability of the rock while the solvent used directly impacts the quantity of asphaltene and clay present. Asphaltenes as insoluble in n-hexane, therefore they precipitate out of the oil onto the rock, interacting with the clay and water to produce a less oil-wet surface, the CS however is composed of heavy dearomatized hydrocarbons which range from C 11 -C 16 and enable more asphaltene production, as all produced oil samples showed. This study provides a data set for wettability alteration during steam-solvent processes. Our finding suggests that solvents control the wettability alteration due to their interaction with asphaltenes. Wettability varies according to the precipitated asphaltenes polarity and the distance from injection well.

Closed Loop Reservoir Management (CLRM) aims to automate the classic reservoir management process by means of using artificial intelligence, control theory and optimization workflows. One of the tasks performed during a CLRM is the optimization process which deals with defining the best allocation of resources so as to maximize, for instance, Net Present Value. This resource allocation may be wells location, injection (or production) rate for each well, etc. In this context, the goal of this paper is to introduce an innovative approach of CLRM for optimization of waterflooding process by using Voidage Replacement Ratio (VRR) as a decision variable to generate optimum NPV of a given field. It is argued that this decision should be taken prior to any definition on well injection rates or either zone injection rate for Intelligent Wells. A simplified oil-water reservoir model is used to simulate real field behavior under a number different scenarios of VRR values defined by an optimization algorithm designed to reach maximum value of a simplified NPV function. From that initial model, three case studies are performed to answer three questions: How can different reservoir and economic scenarios impact decision of the optimum value of VRR to be pursued by reservoir managers?; How to adapt the proposed method to different development project drivers? Is it possible to improve field's performance by defining an optimum sequence of variation for VRR through time? This paper demonstrates that, although being the most common practice for waterflooding projects, a strategy of keeping VRR ~ 1 do not always lead to optimal profitability in terms of NPV. They are also discussed the many aspects to be considered when deciding on the pressure management strategy for developing a reservoir safely and economically while limited by technical and operational constraints. The studies performed demonstrate how an active VRR management during production lifetime might generate improved efficiency of company's assets aligned to its development strategy. Also, a reliable rule of thumbs guideline is presented to give operators a qualitative insight on how different geological and economic scenarios might impact on the definition of optimum strategy for VRR management.

This paper shows the comparison obtained in the oil and gas production increase by cyclic gas injection produced at Provincia field and the cyclic solvent + gas injection (same field). According the composition of the production gas of Provincia Field ( Table 1 ) used during the cyclic injection, is denominated as "rich gas", the molar fraction between C2 to C7+ is 31%. The Provincia Field is a mature field that has since the late 80's the Gas Lift as artificial lift system and for our particular case, that resource compressed gas was taken at 1000 psig to cyclically inject gas production. Besides, the cyclic gas injection & cyclic solvent + gas injection technology was proved. The cyclic rich gas injection of was put in practice in 9 wells of the field and the cyclic injection + gas was applied in the well Santos 94. For our specific case, the application of both technologies in the increase of productivity obtained in Santos 94 (API Gravity 20°) is going to compare. During the total cycle of injection & production of cyclic gas in Santos 94 an increase of oil production was obtained, 2134 Bls and 32,4 MMCF of gas. The oil and gas incremental production during the injection cycle of solvent + rich gas was 3232 Bls and 171 MMCF (32715 Equivalent Barrels).

The process of extracting low gravity, heavy oil from production wells is a practice that can induce formation damage in the reservoir that can severely impact the productivity of a well. Often times, operators will attempt to stimulate production using traditional stimulation techniques which are not always effective or practical in heavy oil reservoirs. The objective of this document is to provide practical guidance for production engineers and well managers that may be unfamiliar with well stimulation in heavy oil environments. Extensive field experience with heavy oil well remediation has provided key building blocks for maximizing production from heavy oil producers. This document details the common types of formation damage observed in cyclic steam and steamflood environments as well as in cold non-thermal wells. The methods used to identify the potential damage mechanisms rely primarily on decline curve analysis and where applicable, wet analysis in the lab. Once a proper determination has been made, a chemical treatment program to address the specific damage mechanism can then be designed. In many cases, a lack of understanding of the damage mechanisms in play can lead to the application or mis-application of unconventional treatments that can damage a well even further. These actions could result in the premature abandonment of an oil well with recoverable and economically viable crude. With the proper knowledge and product application, production can often be restored to pre-damage producing levels, often with sizeable incremental gains. The combined systematic approach of evaluating production profiles, produced fluids, making proper product selections, and selecting proper placement techniques provides a recipe for a greater chance of a successful chemical stimulation program and increased production.

Heavy oil production presents tremendous challenges in subsurface development, production wells, and surface transport. Therefore, highly efficient transportation calls for innovative engineering processes to facilitate the transport from subsurface to downstream. In Block 192- Peru, previous production experience indicated that mixing light oil at the well production manifold to heavy oil stream was a feasible option. However, this option strongly depends on the availability of light oil. The aim of this study is to present alternatives to improve heavy oil transportation performance in the block 192. Results of a fundamental study conducted on the heavy oil transportation performance in Jibaro, Jibarito and San Jacinto fields are presented herein where multiple possibilities are evaluated to reduce the ratio of light oil per barrel of heavy oil production (i.e. to increase the efficiency of the diluent). This study provides guidelines to select one of the three following methods: diluent injection, emulsion injection or reservoir-based technology. Previous operators performed extensive reservoir characterization and simulation modeling which led to recovering over 200 million barrels of heavy oil (up to July 2015) through Vivian sands. Therefore, this confirmed the suitability of introducing new methods to feasible transport and sell heavy oil. Jibaro, Jibarito and San Jacinto fields are used in this study due to their significant heavy oil reserves. The complexity of these fields includes high water cut production, Heli transportable logistics and high cost of produced oil. The first method proposed in this study consists of injecting a diluent in the extraction stream of heavy oil up. The second method uses emulsion water to transport high viscous oil. The third method involves applying a technology in the extraction process to reduce the viscosity of heavy oil, and in-situ upgrade the heavy oil up to sales specifications with a consideration of long distance between fields. This study concludes that a conceptual engineering and a selection of a compatible diluent and solvent are critical. Finally, environmental permitting increases the complexity of any project in the area and the possibility to introduce new technology.

This paper compares the effiency of heavy oil recovery factor by water and polymer flooding under different level of temperature (26°, 50° and 75°C). The performances of both methods were assessed by analyzing the fractional flow curves and the oil recovery factor (%OOIP) for the same temperature. Rheological measurements were carried out to characterize and to select the fluids. Buckley-Leverett model was applied to evalute the effectiveness of the recovery method after the injected fluid breakthrough. Due to the high oil viscosity, the displacement for water flooding is unfavarable. However, the polymer addition improves the viscosity ratio injected/displaced fluids, making the displacement front more sharp. The fractional flow curves showed that the polymer flooding reduces the amount of the remaining oil more than water flooding and the oil recovery are greatly influenced by the test temperature. As the temperature increases, the oil recovery increases, for both methods. At the same temperature, the final oil recovery is equal for water and polymer flooding, showing that the used polymer has not affected the residual oil saturation. However, the polymer flooding was able to anticipate the oil production and the anticipation was more pronounced for higher temperatures. The mobility ratio reduction with temperature rising turned the displacement more piston-like, highlighting the anticipation of the produced oil by polymer flooding.

The present article is based on the enhaced recovery pilot in Argentina presented in SPE 160078 ("Desing and Execution of a Polymer Injection Pilot in Argentina"). A polymer injection pilot is being conducted since January 2012 in El Corcobo Norte field, in Neuquén Basin, Argentina. The project intends to evaluate the incremental volumetric efficiency for Lower Centenario formation, unconsolidated, strongly water-wet sandstone that has been under waterflood since the beginning of the field's production in 2006. El Corcobo Norte field produces medium-heavy oil and, due to its unconsolidated nature, production strategy involves massive sand production all along the well's productive life. Although waterflooding efficiency has allowed achieving an important oil recovery, wormholing and chanelling issues represent a challenge to the field's development strategy of increased injection and fluid production. A polymer injection project would help increasing ultimate recovery factor, through enhacing injected fluid's efficiency to displace the oil. Along the past four years of experience operating this pilot, many lessons learnt regarding process, operational, logistic and chemical issues, became extremely valuable for the company's know how in operating this technology. Pilot surveillance has proven to be a key factor for understanding how the process is working in the reservoir. This work will present the updated results of the polymer injection pilot, which is still under evaluation but already showing promising results that could lead to an attractive expansion project.

The flow of fluids through sand control apertures, such as slots in slotted liners, is critical to the performance of heavy oil wells using Steam Assisted Gravity Drainage (SAGD) or other enhanced methods. Advanced optical image techniques were used to measure the in-situ flow velocity and pressure difference along slots of varying cross sectional profiles. The experimental slot was made as a two-dimensional channel in acrylic sheet to allow excellent visualization. The slots were full scale and varying in geometry: straight slots, keystone slots, and wire wrap screens were evaluated. Measurements were made for a Newtonian fluid (water) at different flow rates over the ranges expected in the field. Captured velocity profiles and non-dimensional pressure were compared with analytical theory. The corss-sectional profile of the slot affects flow characteristics which in turn affect the pressure difference developed across the sand control screen.

Steam injection is a known Enhanced Oil Recovery technique with application in heavy oil exploitation. The process is generating a rather high amount of carbon dioxide (CO 2 ) that according to the current climate regulatory initiatives should be reduced. CO 2 injection to enhance heavy oil production is a known technique for such reservoirs. The technology of capturing CO 2 has evolved today up to a point where it can also be applied to steam generators. This work starts with a comprehensive review of most recent steam generator developments and their possibility of subsequently capturing CO 2 . Co-generation concepts will also be investigated and their potential to generate steam and CO 2 for heavy oil enhanced recovery will be evaluated. The thermal properties of CO 2 are well known, and its critical state poses challenges in many injection applications. This low-cost completion is proposing a parallel injection of steam through tubing and CO 2 through annular space. While injecting CO 2 in a steam-heated well, the elevated temperature keeps the carbon dioxide gas away from its critical state. The gas will cool down the upper part of the well, especially the surface casing, avoiding cement damage and well integrity breaches. This paper describes an economical completion technique that replaces the expensive thermal packer with a new budget-friendly design. This novel setup allows free tubing expansion and protects casing against high temperature through continuous gas circulation in the annulus. It also enables the simultaneously injection of combustion gases from steam generators or other gas supply. In this manner, substantial CO 2 credit could be saved by operators while cutting completion expenses and environmental hazards at the same time.

The advancing high resolution scanning technology has formed a concrete basis for simulation of pore events within microstructures. Interactions between capillary, gravity, and viscous forces result in complex flow phenomena affecting pore-scale physics and phase distributions during different displacement scenarios. Consequently, a myriad of techniques has been proposed to deal with all effective forces and dynamically simulate pore scale multi-phase flow physics. In this regard, the significance of each force, particularly viscous forces, on pore-level flow morphology is not yet well studied. Here, the Navier-Stokes equation along with a VOF volume tracking advection equation is applied for simulation of two-phase displacement scenarios considering gravity, capillary, and viscous forces. A pore-throat pair is used as a simple pore-level geometry to conduct a comprehensive sensitivity analysis and investigate the effect of viscosity, IFT, contact angle and velocity on the trapping amount of non-wetting phase. The results are in good agreement with available experimental data and confirm that in pore-level transport phenomena, the amount of residual trapping is a function of pore-throat geometry and wettability and is not affected greatly by interfacial tension or differences of viscosity. The analysis also demonstrates that within microscale porous media images the gravity role is negligible due to low Bond number values. A pore morphology-based quasi-static approach is then applied to a multi-pore micro-tomographic sandstone image to simulate drainage, and imbibition processes and investigate the effect of geometry, contact angle, and IFT on the amount of heavy oil residual trapping.

Well completions in Latin American oil and gas fields are characterized by many challenging conditions, including reservoir traps with high structural and sedimentological complexity, diverse hydrocarbon reservoir fluids and rock properties, as well as fluid PVT properties and wettability characteristics that vary regionally within a reservoir. In addition, production units on land, offshore and particularly in deepwater environments have limited gas and water treatment capabilities. Accordingly, the objective of many assets is to produce at the lowest possible gas-oil ratio (GOR) and water cut (WCUT). Horizontal wells are often completed with conventional slotted liners. Historical production data confirmed by several production logs indicate that a vast number of wells are under-performing due to non-uniform reservoir influx along the wellbore. This results in early water or gas coning and uneven reservoir drainage that leaves valuable bypassed oil in the ground. To compound the issue, the rapid production increase of highly mobile fluids such as water or gas generates high operational costs for fluid treatment, re-injection, and disposal. Previous publications have explained Inflow Control Devices (ICD) and Autonomous Inflow Control Devices (AICD) principles and design. This paper present and describes examples of successful inflow control device installations in oil well producers in Latin America; installed to produce oil while restricting unwanted water in heavy oil reservoirs. A few variation of inflow control types covering a wide rnage of oil viscosities from 0.6 to 1000+ cP and rock properties and installations in already pre-installed screens to minimize water and gas entry, balance GOR, pressure drawdown aimed to re-vitalize mature fields. ICDs and AICDs technologies have shown robustness and production performance, reducing high water production at a well, group or field level, extending production life and reducing production costs by minimizing the risk of handling unwanted fluids at the surface and leaving bypassed oil underground.

Due to the high temperature, high pressure and sophisticated chemical environment in heavy oil wells, Steam-Assisted Gravity Drainage (SAGD) is considered one of the most challenging service conditions for carbon steel equipment. This paper introduces an advanced metal-metal bonded coating technology-electroless nickel (EN) coating and its applications in SAGD operations to protect downhole equipment from fouling due to corrosion, adhesion of inorganic and organic materials as well as the impacts of wettability alteration. In the first chapter, we will describe the complex and hostile thermal-chemical environment, their impacts on the SAGD production system and the fouling causes. We will compare the performance of EN coating to that of regular carbon steel pipe in the following aspects: a) corrosion resistance in the presence of sour gases using potentiostatic and potentiodynamic polarization methods; b) adhesion of silica, bitumen coated silica using atomic force microscopy, and c) surface energy and wettability alteration using contact angle measurements. The set-up of the facility, procedures of the tests and governing science and engineering principles will be reviewed. In the end, we will introduce the results of laboratory and SAGD field experiments designed to investigate the EN coating technology in protecting the substrate materials under SAGD conditions.