In recent years, chemical enhanced oil recovery (EOR) application for heavy oil fields has been limited by low oil prices. The use of chemicals, though proven to be effective, can be toxic, expensive, and/or non-biodegradable. Deep Eutectic Solvents (DES) are potentially a much cheaper, greener alternative to conventional surfactants. However, there are very limited studies on the DES application. This study focused on numerical modeling of the effectiveness of a specific DES (Choline Chloride: Glycerol), in improving oil recovery and evaluating the parameters affecting the DES behavior. Data was gathered based on a literature review of the various but limited studies available and used to construct a black oil numerical model representing a heavy core-flooding experiment. The model was calibrated to some of the available published data. The study then used this model to examine different scenarios by comparing the performance of conventional water flooding using formation brine, with the performance of DES injection (after an initial period of brine flooding). The simulations were repeated at multiple temperatures and concentrations. Simulation results tally with the hypothesis and published data which is in favor of oil recovery enhancement with DES injection. In brine flooding cases, the oil recovery factor was in the range of 36-39%, with the high end occurring at a higher temperature. Increasing the DES concentration reduces the interfacial tension (IFT) which further improves oil recovery with the assistance of wettability alteration. Injected DES alters the rock wettability from oil-wet to water-wet thus improving the oil mobility. It was also observed that the oil recovery factor increases significantly with the increase of temperature as this reduces the oil viscosity and in turn, the mobility ratio, given the same formation properties. The highest recovery factor (60-62%) was achieved at the maximum injected concentration although this may not be practical in field application. Based on this, DES performance can be successfully applied as a substitute for current surfactant flooding methods in light of its low-cost, ‘greener’ nature as well as performance as a chemical EOR agent.

The first horizontal oil well was drilled through an anticline structure in the Block-7E of East Flank, S-field, penetrating three production sands Sand I, Sand II and Sand III. Based on a comprehensive pre-drill study through steady-state and 3D dynamic time lapse simulation, Inflow Control Device (ICD) with integral sleeve (on/off function) attached to the ICD's joint is the optimum development of the fault block that maximizes zonal control for contrasting water encroachments. Due to the unconsolidated nature of the target reservoir, this well is designed for Open-Hole Gravel Pack (OHGP) with specialty 3D filtration screen to manage sanding issue. This paper highlights 2-in-1 application of ICD with enabled zonal shut-off sleeves and the OHGP completions with external screen. A pre-drilled ICD dynamic modeling is constructed to evaluate the well performance with ICD configuration. The design criteria for an optimum ICD design configuration is based on number of compartments and size, packer placement, ICD nozzle sizes and numbers. This dynamic single well model was used to justify the technology value which resulted in production improvement (maximizing oil and minimizing/delaying water). However, during the drilling of this well, the pre-drilled model is then updated in real time with the input of actual petrophysical data from Logging While Drilling (LWD) measurements along the OH section. Actual well trajectory and structure adjustment encountered while drilling were also co-utilized to determine the final optimum ICD design for the field run-in-hole (RIH) completion. Target fault block in S-Field East Flank requires optimum development strategy for its economic viability (Kumaran, P. N et al. 2017). Only one open-sea discovery well proved the oil bearing sands to-date, but a lot of uncertainties remains: geological structure, fluid contacts, fluid characterization, existence and nature of an aquifer, etc. Hence, all these uncertainties are incorporated in the ICD optimization through sensitivity analysis and uncertainty range estimation. Oil production improvement with water reduction while delaying water encroachment are key in the optimization of the ICD design, which is achieved by evaluating the impact of ICD's influx balancing throughout the horizontal section. Study shows that water encroachment is effectively controlled with 9 compartmentalization zones along the horizontal section, each one separated using oil swellable packer. After 7 months of stable flow, well test is showing zero-water and zero-sanding to surface with well controlled production rate that can produce more if required. This is the testimonial of the deployment success from its initial conceptual design to its ultimate completion.

In the current period of industry downturn, creating and executing opportunities to develop an offshore brownfield has become more economically challenging. This paper describes the technical, commercial, and operational aspects that helped in achieving an established economical cut-off for project sanction. The project will enable sustaining field average oil production above operational economic limits thereby maximizing field life. With the prevalent low oil price conditions, the economic threshold for projects sanction and execution has reduced. The asset team faced a challenge to achieve a UDC threshold of USD16/bbl. Multi-disciplinary team was tasked to look at key aspects to improve project commerciality. Subsurface recovery potential was assessed thoroughly to evaluate the impact of subsurface uncertainty, and evaluate the impact on well designs on the project cash flow. Wells were designed to tap multiple reservoir targets to minimize subsurface risk through existing facilities to maximize ullage. The wells were drilled from new slots via small deck extension instead of the high-risk slot recovery option, which helped to reduce the Capital Expenditure (CAPEX). Fit-for-purpose and cost optimized wells were designed by minimizing automation (i.e.: ICVs, PDGs, etc.) which also reduced operating risk and cost. Multiple sands were targeted in different compartments with different pressure system, hence planned not to commingle production. Hence, only one primary reservoir was completed, with other zones kept behind casing for future intervention with bottom-up production strategy. This helped deferring the project investment as this was in the intervention cost in Operating Expenditure (OPEX) which helped to improve the project economics. Further cost savings were achieved by accelerating the project in order to achieve synergy with an upcoming drilling campaign. The reduction of the overall project CAPEX, thus allowed the project to be commercially feasible and technically sound for execution. In addition, the team has also established a reservoir management plan with mitigation plan to deal with the main subsurface and surface risks. The out of box solution of optimized field development plan for complex offshore brownfield with limited facilities modification, while being cost conscious but still ensuring technically sound concept proved to provide the answer for sustainable production growth in S Field at low oil price environment. This paper will also highlight the key lessons learnt and obstacles which were observed during the execution of the project are expected to become guidelines for future low cost projects in this region.

To create opportunities for economic development in an offshore brown field with well-known subsurface and operational complexities, in an industry downturn. This paper describes the technical, commercial, and operational aspects that helped in achieving an established economical cut-off for project sanction. The project will enable sustaining field average oil production above operational economic limits thereby maximizing field life. With the prevalent low oil price conditions, the economic threshold for projects sanction and execution has reduced. The asset team faced a challenge to achieve a UDC threshold of USD16/bbl. A Multi-disciplinary team was tasked to look at key aspects to improve project commerciality. Subsurface recovery potential was assessed thoroughly to evaluate the impact of subsurface uncertainty, and evaluate the impact on well designs on project cash flow. Wells were designed to tap in multiple reservoir targets to minimize subsurface risk through existing facilities to maximize ullage. The wells were drilled from new slots via small deck extension to optimize cost instead of high risk slot recovery, which helped to reduce CAPEX. Fit-for-purpose and cost optimized wells were designed by minimizing automation (i.e.: ICVs, PDGs, etc.) which also reduce Operating risk and cost. Multiple sands were targeted in different compartments having different pressure support, did not allow commingle production. Hence, only one primary reservoir was completed, with other zones kept behind casing for future intervention with bottom-up production strategy. This helped deferring the project investment as this was in the intervention cost in Operating Expenditure which helped to improve the project economics. Further savings were achieved by accelerating the project in order to achieve synergy with an upcoming drilling campaign. The reduction of the overall project CAPEX allowed the project to be commercially feasible and technically sound for execution. In addition, the team has also established a reservoir management plan with mitigation plan to deal with the main subsurface and surface risks. The out of box solution of optimized field development plan for complex offshore Brownfield with limited facilities modification, while being cost conscious but technically sound concept proved to provide the answer for sustainable production growth in S Field at low oil price environment.

Reservoir compartmentalisation, whether structural or stratigraphic, is one of the most prominent parameter for accurately characterising the distribution of hydrocarbons in the subsurface and it is a key element for optimising hydrocarbon recovery. In order to accurately characterise its compartmentalisation, a new volume-based structural modelling technique have been applied for generating a geocellular model of the complex, highly faulted east flank of the studied field (Sabah, Malaysia). Benefits over existing pillar-based and surface-based techniques are discussed. The volume-based modelling technique consists of interpolating a continuous 3D property representing the relative stratigraphic age of the formations from all available well and seismic interpretation data. A watertight structural framework composed of faults and horizon surfaces is then extracted from this property, and converted to a geocellular grid in which the faults are stair-stepped. New workflows were developed for early integration of fluid distribution and production data during the creation of the geological framework, leading to an accurate delineation of fault compartments. The fault network of the new east flank model is composed of over 90 synthetic and antithetic faults, forming X and Y-shaped truncations and subdivided into over 35 geological units. Fault truncations are located within the volume of interest and have key bearing on the understanding of fault sealing potential. The subsequent 3D grids include all interpreted faults and integrate fluid contacts, pressure and production data, capturing essential compartmentalisation characteristics. The main benefit of the volume-based technique over pillar-based methodologies is that it incorporates all the fault network complexity. Indeed, as their coordinate lines must be parallel to fault surfaces, grids which geometry is extruded along curvilinear pillars can generally not be used to represent fault systems with X or Y-shaped truncations. Besides, grid cells may become excessively skewed in presence of synthetic and antithetic faults, which can trigger inaccuracies when performing flow simulations. Finally, thanks to early integration of production data during the interpretation phase the dynamic model could easily be history matched by adjusting fluid transmissibility across nearby fault blocks and between adjacent sand layers.