Offshore Heavy Oil Reservoirs Research Articles

Experimental study on horizontal-well multi-thermal fluid stimulation process in offshore heavy oil reservoirs

The development of offshore heavy oil is sensitive and complex, which is limited by factors such as platform space, economy, pollution and security, so conventional thermal recovery techniques such as cyclic steam stimulation and steam flooding have difficulty in achieving favorable development effect for offshore heavy oil reservoirs. Horizontal-well multi-thermal fluid stimulation (HW-MTFS) process is a relatively new thermal recovery technique, which combines the multiple advantages of gas injection, horizontal well and thermal recovery process. In this paper, the HW-MTFS physical model was firstly designed. Thereafter, the influences of different factors on steam absorption along horizontal wellbore were studied by sand-packed model experiments. Finally, the development performance of horizontal-well cyclic steam stimulation (HW-CSS) process and horizontal-well multi-thermal fluid stimulation process was compared by two groups of physical experiments. The results indicate that different injection factors significantly influenced the steam absorption along horizontal wellbore. Compared with steam injection, the multi-thermal fluid injection could effectively improve the steam absorption along horizontal wellbore. The HW-MTFS process had a higher oil rate and production, and the recovery of HW-MTFS process was 42% higher than that of HW-CSS in three cycles.

Experimental Study on the Effect of Polymer Injection Timing on Oil Displacement in Porous Media

It has been proven that polymer injection at early times is beneficial to offshore heavy oil recovery. It is of significant importance to optimize the polymer injection timing and decide the residual oil distribution after polymer flooding. Aiming at a specific offshore heavy oil reservoir in Bohai, China, the optimum polymer injection timing is investigated through laboratory experiments. The influence of polymer injection timing on oil displacement and remaining oil distribution is analyzed by combining macroscopic and microscopic flooding experiments. The results reveal that the optimum polymer injection timing should be close to the water breakthrough, i.e., just before the waterflooding front reaches the outlet of the core. In addition, the waterflooding front position is analytically solved by using the Buckley–Leverett method and verified by experimental results, which supply an approach to predict the polymer injection timing. When polymer is injected before the waterflood front reaches the outlet of the core, the mobility control ability of polymer solution can reduce the fraction of bypassed volume of the reservoir by waterflooding. The early injected polymer mainly enters the high permeability zone, which works positively in two ways. Firstly, it improves the oil displacement efficiency of the high permeability zone. Secondly, the polymer establishes a flow resistance in the high permeable zones, thus improving the sweep efficiency in the low and medium permeability zones. However, our residual oil distribution experiments illustrate that there is still a large amount of oil remaining in the low and medium permeability zones. Therefore, it is necessary to explore additional EOR methods to recover the abundant residual oil.

Study on main controlling factors of high injection pressure in offshore heavy oil reservoir

High injection pressure, insufficient steam injection rate and low bottom hole dryness seriously affect the application effect of steam stimulation in offshore heavy oil reservoir. By analyzing the factors affecting the reservoir conditions of high injection pressure during huff and puff, it can be concluded that the oil viscosity increases and the permeability decreases. The grey correlation analysis shows that the contribution of unit viscosity increase to injection pressure increase is twice that of unit permeability decrease. In view of the main controlling factors, the viscosity change of crude oil was studied indoors. The results showed that: 1) The content of heavy crude oil increased, and the viscosity of crude oil increased linearly; 2) The reverse phase point of oil emulsification at reservoir temperature is 50% water cut, and the viscosity of oil-in-water emulsion will increase with the increase of water cut; 3) the higher the viscosity of asphaltene is, the stronger the viscosity is. According to the actual situation of offshore heavy oilfield, residue of heavy components and emulsification of oil-in-water is the main factor affecting steam injection.

Experimental investigation and field pilot testing of air assisted cyclic steam stimulation technique for enhanced heavy oil recovery

Air assisted cyclic steam stimulation (AACSS) process is a novel technique for enhanced heavy oil recovery, which is efficient and economically attractive compared with other non-condensable gases and solvents injection-based techniques. In this study, the performance of AACSS process for an ultra heavy oil reservoir was investigated via laboratory experiments and field data analysis. The results indicate that air injection based on steam stimulation can effectively increase oil recovery in comparison with the conventional cyclic steam stimulation (CSS) process. The injected air can significantly increase and maintain the reservoir pressure, and reduce oil viscosity via flue gas dissolution and the thermal effect of low temperature oxidation (LTO) of the crude oil. The field pilot testing results of the AACSS technique in Liaohe Oilfield (Northeast China) demonstrate that AACSS can significantly increase oil production, prolong the effective production period of time, reduce water cut and the steam to oil ratio. A scoping economic study shows that the AACSS process can be more economically attractive than CSS process in terms of net present value. The AACSS technique has been effectively applied in mature heavy oil reservoirs developed by the conventional CSS, and it is also a feasible option to deep and offshore heavy oil reservoirs. [Received: January 6, 2017; Accepted: August 10, 2017]

Evaluation of the Vertical Producing Degree of Commingled Production via Waterflooding for Multilayer Offshore Heavy Oil Reservoirs

Recently, commingling production has been widely used for the development of offshore heavy oil reservoirs with multilayers. However, the differences between layers in terms of reservoir physical properties, oil properties and pressure have always resulted in interlayer interference, which makes it more difficult to evaluate the producing degree of commingled production. Based on the Buckley–Leverett theory, this paper presents two theoretical models, a one-dimensional linear flow model and a planar radial flow model, for water-flooded multilayer reservoirs. Through the models, this paper establishes a dynamic method to evaluate seepage resistance, sweep efficiency and recovery percent and then conducts an analysis with field data. The result indicates the following: (1) the dynamic difference in seepage resistance is an important form of interlayer interference during the commingled production of an offshore multilayer reservoir; (2) the difference between commingled production and separated production is small within a certain range of permeability ratio or viscosity ratio, but separated production should be adopted when the ratio exceeds a certain value.

OPTIMIZATION FOR DRILLING SCHEDULE OF WELLS IN THE DEVELOPMENT OF HEAVY OIL RESERVOIRS

During the development stage of a petroleum field, one important decision is to define the schedule for drilling the wells. Several general rules were listed for light and heavy oils. However, these rules are not always applicable and it may be important to use simulation models to test and choose the schedule. This paper consists of the development, implementation, and application of two different algorithms for optimization of wells drilling schedule. The first algorithm seeks, for each period, which well brings the best economic output. Once this well is selected, the second period of time is tested considering the remaining wells and this procedure is repeated until the last well. The second procedure is based on the reduction of search space where random schedules are generated and the best results maintained for the subsequent generation of scenarios, only allowing the wells to be drilled in the period that produced the best values of the objective function in the previous step. This procedure is repeated until each well converges to the period that results in the best economic return. Both algorithms were tested in two synthetic fields, based on the characteristics of offshore heavy oil and high average permeability reservoirs. To generate a benchmark for the solutions, a large amount of random schedules were tested and a normal distribution for net present values was generated. Both algorithms can be applied in any type of reservoirs, resulting in a very time consuming process in the cases where simulation time is very high. The results from both algorithms lead to net present values higher than at least 95% of the values from random schedules. For both cases, economic results were significantly better than those found for selecting strategy using wells ranking based in economic indicators, which is a common procedure. Both algorithms are also easy to implement and they can be inserted in a cycle of automated or assisted optimization process.

A New Analytical Model of Productivity Prediction for Offshore Heavy Oil Reservoir With Cycle Steam Stimulation by Horizontal Wells

The heavy oil thermal recovery technology has been widely used in land oil field both at home and abroad, but no precedent of offshore thermal recovery (except beach) was reported so far because of the platform limitation and operating cost restriction. Offshore thermal recovery needs higher oil recovery rate and higher cumulative oil production of each well. As for an offshore heavy oil reservoir, which can produce oil by natural energy of formation, the ratio of thermal productivity and cold productivity (oil productivity increment factor) decides whether development by thermal recovery or not. Due to the huge investment of offshore oil field development, too high or too low productivity evaluation will have serious consequences for oilfield exploration and development, so it is very important to make reasonable prediction of the relative oil productivity index (ROPI). Due to the complexity, there is no prediction model of ROPI for horizontal well CSS. Based on horizontal well productivity formula for cold production, on the basis of heated radius of CSS horizontal well, combining with the viscosity-temperature curve of heavy oil, considering the viscosity changes with temperature in heated area, a new analytical model of CSS horizontal well productivity prediction is derived. By the new model, it is easy to get the ROPI of CSS. The research results show that thermal recovery ROPI mainly influenced by heated radius, reservoir thickness and horizontal section length. Case study of CSS horizontal well in N heavy oil field in Bohai shows that, the average oil productivity of first injection cycle is 1.5 ~ 1.6 times of that of cold production, and it is in accordance with that of the prediction model. The new analytical model fills the gap between the complex numerical simulation method and simple experience method, which is of great significance for designing reservoir project of offshore heavy oil.

Characterization and Prediction of Gas Breakthrough With Cyclic Steam and Gas Stimulation Technique in an Offshore Heavy Oil Reservoir

In this paper, a reservoir simulation study was conducted for the characterization and prediction of gas breakthrough during the development of cyclic steam and gas stimulation (CSGS) for a horizontal well. A new concept named the gas breakthrough coefficient (GBC) was proposed to characterize the gas breakthrough degree quantitatively, and a regression model and two calibration curves were established to predict the gas breakthrough degree. The method of foam plugging to inhibit gas breakthrough was also discussed. It was found that the gas breakthrough degree could be well characterized by the GBC and distinguished as four types: weak, moderate, strong, and severe. The regression model and calibration curves could also be used to predict the gas breakthrough degree under different reservoir and development conditions. Foam plugging was found to be effective to inhibit gas breakthrough when the gas breakthrough degree was moderate or strong.

Production prediction of cyclic multi-thermal fluid stimulation in a horizontal well

Cyclic multi-thermal fluid stimulation (i.e., huff and puff) in a horizontal well is an effective way to recover offshore heavy oil reservoirs. To rapidly predict reservoir production performance, an analytical model for predicting the productivity of a cyclic multi-thermal fluid stimulation in a horizontal well was developed in this study. The underlying assumption in this study is that multi-thermal fluids spread around the horizontal well cylindrically at the beginning of injection and then along the top or bottom as the fluids contact those regions; this creates a composite reservoir with hot and cold zones. First, a production formula for a horizontal well in the composite reservoir described was derived using the equivalent flow resistance method from the water electric analogy principle. A heat diffusion model of multi-thermal fluids was then used to describe how the fluids spread out in the reservoir. Then, an evolution model of the physical fields was built by considering the enhanced oil recovery mechanism of multi-thermal fluids, which describes the evolution of temperature, pressure, oil viscosity, relative permeability curves, etc. during the huff-and-puff process. A new formula was used to determine the reduction in viscosity caused by carbon dioxide present in the fluid. The desired production prediction model was then established by coupling the developed production formula, heat diffusion model and evolution model. The analytical model was verified by numerical simulations and application to an offshore oil field. This study described an effective and quick method for productivity prediction, reservoir dynamic analysis and injection optimization.

Optimization of thermal recovery strategies for offshore heavy oil reservoirs in Bohai Bay, China

ABSTRACTA series of experiments were conducted to test thermal conductivity, heavy oil-water, and heavy oil-steam relative permeabilities used in thermal simulations. The effects on these parameters of temperature, pressure and heavy oil viscosity were also studied. Reservoir simulations were conducted to optimize thermal recovery processes for three heavy oil reservoirs with a range of in situ oil viscosities from 342 to 926 mPa·sec by comparing different operating strategies. The results show that multicomponent thermal fluid flooding achieved better performance for lower viscosity heavy oil. However, steam flooding was found to be more effective for intermediate and higher viscosity heavy oil.

Quantitative characterization of interlayer interference and productivity prediction of directional wells in the multilayer commingled production of ordinary offshore heavy oil reservoirs

Based on the physical experiment of visible multi-tube water flooding, in combination with field production data, the interlayer interference in multilayer commingled production of ordinary offshore heavy oil reservoirs is quantitatively characterized and an appropriate productivity prediction method of directional wells is established for multilayer commingled production of ordinary heavy oil reservoirs. The dynamic relationship of interference coefficients between fluid and oil production indexes is obtained for the multilayer commingled production of ordinary heavy oil reservoirs. The Vandervlis directional well productivity equation is revised by introducing interference coefficient with consideration of starting pressure gradient and a dynamic productivity prediction equation is finally established suitable for multilayer commingled production of ordinary heavy oil reservoirs. Interlayer interference is mainly controlled by vertical reservoir permeability difference, which can be comprehensively characterized by reservoir reference permeability, permeability contrast and permeability deviation. The productivity of wells with different water-cut stages is variously affected by interlayer interference. This influence will be intensified in high water-cut situation, which needs appropriate adjustment measures. The productivity can be more accurately predicted by considering interlayer interference, and the revised directional well deliverability equation can be well applied to field production.

Study of Mechanisms of Enhanced Oil Recovery by Multi-Thermal Fluids

A new process using multi-thermal fluids as an innovative technique for recovery of offshore heavy oil has been used in Bohai oilfield pilot tests. However, the mechanisms of its enhanced oil recovery and reservoir adaptability (sensitivity) have not been studied in depth. Through theoretical, numerical simulation and experimental analyses, the stimulation mechanisms of various components in this process and the coupling effects between these components in terms of enhanced oil recovery are studied and analyzed in detail. In addition, using oil viscosity, rock permeability and heterogeneity parameters of heavy oil reservoirs in the Bohai oilfield, production results and adaptability to reservoir conditions between the standard steam stimulation process and the stimulation process of multi-thermal fluids are compared. The results indicate that the latter process can enlarge the radius of a thermally swept volume, increase formation energy, and reduce heat loss, but the total enthalpy carried by this process drops slightly. Consequently, the process of multi-thermal fluids stimulation is more suitable to heavy oil reservoirs whose oil viscosity is not too high, heterogeneity is relatively weak, oil formation is thin and natural energy is low. Key words: Offshore heavy oil reservoirs; Multi-thermal fluids; Cyclic steam stimulation; Stimulation mechanism; Production efficiency; Reservoir adaptability; Bohai oilfield

Technology Focus: Heavy Oil (March 2015)

Technology Focus This past year witnessed significant activity and growth related to heavy-oilfield developments worldwide, and this was accompanied by a record number of SPE paper submissions on related topics. This feature article highlights several technical focus areas identified in this new literature set. On the basis of field experience, operators have recognized the importance of developing and implementing technologies that improve inflow conformance to facilitate uniform steam-chamber development along steam-assisted-gravity-drainage (SAGD) production wells. Several papers describe the development, testing, and field piloting of completions that incorporate various types of inflow-control de vices (ICDs). While most of these consider passive or autonomous control de vices, one paper describes the installation and early performance of an intelligent-well-completion system with full surface activation and control of the ICDs in an SAGD well. Technical challenges associated with sand control, erosion, scaling, and plugging also must be addressed as these various systems evolve and their use continues to grow. Significant attention was also given to solvent-based recovery methods with more than three dozen papers on various aspects of modeling, experimental evaluation, and field piloting of different solvent recovery schemes. This work contributes to the understanding of the complex chemical and physical processes involved in applying such recovery methods in different reservoirs and thus will assist operators in the effective screening, design, and commercial implementation of these techniques. As an example, another paper offers insights to the simulation community on methodological aspects of modeling hybrid steam/solvent processes. The exploitation of offshore heavy-oil reservoirs continued to be a focus for operators in many regions. The literature describes comprehensive appraisal and development planning programs as well as various studies and field pilots undertaken to screen/evaluate alternative primary- and enhanced-recovery methods (including polymer floods and various thermal processes) for these applications. One paper outlines the strategies pursued to address the challenges involved in developing a high-viscosity heavy-oil reservoir in the North Sea. Additional focus areas include advanced simulation techniques, new polymer developments and field applications, reservoir characterization and recovery surveillance, recovery strategies for fractured carbonate reservoirs, thermal-well design and integrity, caprock integrity, rock- and fluid-property determination, artificial-lift performance and reliability, and in-situ-combustion and electrical-heating recovery methods. The additional-reading papers and many others on these topics can be found in the OnePetro library. With the decline in oil price and typical product differentials, the current year will be particularly challenging for heavy-oil operations. However, as in the past, these conditions also create opportunities for technology development and deployment to improve operational performance and efficiency, and this should remain a priority for the industry. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 172850 Polymer Flooding for Extraheavy Oil: New Insights on the Key Polymer Transport Properties in Porous Media by F. Rodriguez, Paris Diderot University, et al. SPE 169678 Maximizing Steam-Project Value in South Oman Through Flexible Development Phasing and Integrated Reservoir Surveillance by S.M. Al-Hinai, Petroleum Development Oman, et al. SPE 172889 Maximizing the Profitability of Extraheavy-Oil Wells With Cyclic Steam Injection in the Samaria Neogeno Field by Using Injection Profiles Logged Under Extreme Temperatures by Ezequiel A. Isidro Torres, Pemex, et al. SPE 170109 A Case Study in the Application of Bitumen Geochemistry for Reservoir Characterization in SAGD Development by J.N. Sereda, Suncor Energy, et al. SPE 169513 Case Study: Steam-Injection Step-Rate Tests Run in the Shallow Low- Permeability Diatomite Formation, Orcutt Oil Field, Careaga Lease, Santa Barbara County, California by Ramon Elias, Santa Maria Energy, et al.

The Effects of Multi-component Thermal Fluids on the Viscosity of Offshore Heavy Oil

Multi-component thermal fluids stimulation is a feasible way to recover offshore heavy oil reservoir. As a new technology, its mechanism of enhanced oil recovery should be understood through systematic simulation experiments and quantitative analysis. Laboratory experiments were carried out to investigate the effects of temperature, natural gas, and various gases (N2, CO2, or N2+CO2) on the viscosity of heavy oil from Nanbao block of Bohai offshore oilfield. The results show that in the range of 56°C (reservoir temperature) to 120°C, natural gas saturated and degassed oils are all very sensitive to temperature, and the viscosity is reduced by more than 90% when heated to 120°C; under lower temperature condition, injection of 5MPa N2, N2+CO2, or CO2 can significantly reduce the viscosity of natural gas saturated heavy oil, with a viscosity reduction ratio of about 20%, 50%, and 80%, respectively, at 56°C. Therefore, heavy oil production by viscosity reduction can be achieved by raising temperature or through gas injection. Taking into account the equipment, heat loss, and cost of steam injection, the technology of moderate heating, auxiliary gas injection is very promising for the recovery of Nanbao heavy oil.

Study on the Surfactant/Polymer Combination Flooding Relative Permeability Curves in Offshore Heavy Oil Reservoirs

Different kinds of compound solutions were prepared by using different concentrations of hydrophobically associating polymers and sulfonate type surfactant. The static viscosity and interfacial tension of these solutions were measured. On the experimental conditions of the Suizhong 36-1 oilfield, the relative permeability curves of the water flooding and the surfactant/polymer combination flooding were measured through the constant speed unsteady method and the experimental data were processed through the way of J.B.N. The several existing kinds of viscosity processing methods of non-newtonian fluid were compared and analysed , and a new way is put forward . The results show that the relative permeability of the flooding phase is very low while displacing the heavy oil; the relative permeability of oil in combination flooding is higher than that in water flooding, the relative permeability of flooding phase in combination flooding is lower than that in water flooding and the residual oil saturation of combination flooding is lower than that of water flooding. Meanwhile, the concentrations of polymer and surfactant have a great influence on the surfactant/polymer combination relative permeability curves.

Application of Particle Swarm Optimization for Enhanced Cyclic Steam Stimulation in a Offshore Heavy Oil Reservoir

Three different variations of PSO algorithms, i.e. Canonical, Gaussian Bare-bone and Levy Bare-bone PSO, are tested to optimize the ultimate oil recovery of a large heavy oil reservoir. The performance of these algorithms was compared in terms of convergence behaviour and the final optimization results. It is found that, in general, all three types of PSO methods are able toimprove the objective function. The best objective function is found by using the Canonical PSO, while the other two methods give similar results. The Gaussian Bare-bone PSO may picks positions that are far away from the optimal solution. The Levy Bare-bone PSO has similar convergence behaviour as the Canonical PSO. For the specific optimization problem investigatedin this study, it is found that the temperature of the injection sCO2 composition in the injection gas, and the gas injection rates have bigger impact on the objective function, while steam injection rate and the liquid production rate ha ve less impact on the objective function.

Correction Method of RPM C/O in Offshore Heavy Oil Reservoir

At present, the most advanced remaining oil saturation logging technologies are RPM RST RMT PNN PND in domestic and outside. But these have only been made some correction of porosity, lithology, borehole conditions, formation water salinity, oil density. So they are not suitable for application in the offshore heavy oil reservoirs of gravel pack. The writer has designed a volumetric model of considering gravel pack, casing size, wellhole liquid and so on. And some correction formulas are deduced with single factor and multiple factors by combining this volume model. While the author use these formulas to establish some theoretical charts. In the case of that the porosity is 0.3, the author analyzes the C/O value change rule with the same oil saturation in sandstone strata. When the gravel packing volume of 0.1, the C/O value decreases about 0.15. When casing diameter increases from 6inches to 7inches, the C/O value increases about 0.2. When the casing diameter is 6inches, make the clay content, gravel content, and calcium content for 0.1, the C/O value increases about 0.6. After making the gravel pack and other influencing factors correction, contrast RPM data interpretation results and PLT data interpretation results. It is found that the results of remaining oil explain accuracy is improved 10% or more. These methods provide a new theoretical basis for the offshore heavy oil reservoir in the fine interpretation of RPM data.

Technology Focus: Multilateral/Extended Reach (May 2010)

Technology Focus Exploration and development projects suffered from uncertainties caused by downsizing of the worldwide economy last year. Wide variation in value of our main commodities caused delays in several offshore oil- and gas-asset projects. Our industry must ask if it has done enough to deal with these variations in commodity values and what would be the best way to mitigate their influence in the current market. Current statistics show that there is a long way to go. The cost of nonproductive time (NPT) is very high and needs to be mitigated. The importance of improvement performance in a critical economic environment is crucial to maintain our business. The main question is how to keep the interest of investments in this scenario. Fundamental to evaluating techniques, equipment, and design is understanding the risk variability. Professionals must respond to a more-fluid, less-certain business environment than did their predecessors. Assessing data and planning and executing a well involve a complex interaction of data, regional knowledge, and field experience. Different subjects not considered before such as communication skills, adding value, team building, and networking have a major role in mitigating the risks and in improving the performance and financial return of a project. These dynamics, along with increased globalization, require a broader set of skills. We are succeeding in drilling and producing wells in water depths and measured depths greater than 10,000 and 35,000 ft, respectively. However, decreasing NPT to acceptable ranges has not happened. Although innovative technologies have been implemented over the last 10 years that enable exploration and development in environments with difficult tectonic stress and subsalt or presalt wells, we still lack efficiency. In offshore operations that cost our industry more than USD 1.3 million/D, the current NPT between 20 and 30% in several areas of the world is not acceptable. For the sake of future business, operators and service companies should work together not only in development of new technologies but in aligning common goals such as a consistent NPT less than 5% in operations, which would guarantee several projects. This target requires a common goal of operators and service companies who, unfortunately, to date, have not been brought together, but in the current environment it is essential for our future. Multilateral/Extended Reach additional reading available at OnePetro: www.onepetro.org SPE 128314 • “Multilateral Wells Reduce CAPEX of Offshore, Subsea Development in Australia’s Northwest Shelf” by Brett Lawrence, Apache Energy, et al. SPE 128461 • “Successful Application of Dual-Lateral Junction Technology To Develop a Marginal Gas Field in the Carboniferous Area of the UKCS Southern North Sea” by A.J. Hatch, E.ON Ruhrgas, et al. SPE 128915 • “An Experimental Study To Define Operational Parameters Governing Hole Enlargement While Drilling Offshore Heavy-Oil Reservoirs” by F.G. da Costa, Petrobras, et al.

Application of multilateral wells with limited sand production to heavy oil reservoirs

Multilateral wells with limited sand production are proposed to produce offshore heavy oil reservoirs. This technique was studied through lab experiments and numerical simulation. Permeability increases with sand production and formation fines of less than 39 μm diameters are the main fines that jam pore throats and influence permeability the most. For a given total length of branches, productivity slightly decreased with increasing branches, suggesting that the number of branches should not be very higher, two or three are better; and productivity increased with the increase of branch angles, but the increase of productivity decreases. Field test was carried out in NB35-2 oil field and the individual layer deliverability of a multilateral well with limited sand production is three times the multilayer production of the common deviated well.

Uncertainty Analysis in the Seismic to Reservoir Simulation Workflow for a New Offshore Heavy Oil Development

Abstract This paper presents the work of a multi-disciplinary team of earth scientists and engineers to create a development plan for an offshore heavy oil field while accounting for uncertainties in the geological and reservoir simulation models. The field is located in shallow waters and has oil ranging in viscosities from 20 cp to 200 cp. The depositional environment is a fluvial meandering river system where the sands are relatively thin and disconnected. The field is penetrated by a good spread of appraisal wells, is covered by 3D seismic data, and has extensive measurements of rock-fluid properties and geochemistry analysis. Some of the appraisal wells also have good quality DST and MDT data which was used to constrain the geological model. The workflow is comprised of constructing a geological model using deterministic geobodies identified from interpretive analysis of seismic relative acoustic impedance coupled with stochastically defined sands in areas of poor seismic quality or below the threshold of seismic resolution. The distribution and density of these stochastic sands were tied to well control and guided by stratigraphic layering statistics using a truncated Gaussian simulation technique. Results of both techniques were merged into one final model, embedded into a shale background facies. Various field development scenarios were considered, including inverted five-spot and nine-spot pattern waterfloods, along with the application of horizontal wells. Development scenarios and predictions incorporated uncertainties in wateroil contacts, net-to-gross ratios, oil viscosities, relative permeability, residual oil saturations, injectivity, and skin factors. The use of experimental design techniques and parallel simulation enabled the team to capture the range of uncertainty in subsurface and engineering parameters while keeping computational times manageable. The paper discusses some of the key uncertainties and challenges in bringing this and similar reservoirs to development. Introduction The ability to make quick yet intelligent and value-added decisions to develop new fields has always been of great significance. In situations where the capital expenses and subsurface risk are high, carefully analyzing the inherent uncertainties in the reservoir and how they impact the predicted production becomes a daunting task. The problem is compounded in offshore environments, especially in the presence of heavy oils and disconnected sands, where the margin for error is small. In many cases, realizing the value of a prospect is very time-dependent and resolving uncertainties of complex reservoir systems needs a systematic and efficient approach. This paper presents the case study of the uncertainty analysis workflow for a new offshore heavy oil reservoir for which a development decision had to be made in a short timeframe (a few months). The field is located in shallow waters and is penetrated by 11 exploration/appraisal wells. The depositional environment is predominantly a fluvial meandering river system, where the sands are relatively thin (5 – 15 m in thickness) and disconnected. All the appraisal wells have good quality log data and several attempts were made to tie reservoir zones to 3D seismic attributes.