Cyclic waterflooding has received recent attention since many studies and field tests have shown that it may lead to additional oil recovery at virtually zero additional cost. Even though the process is in principle very similar to conventional waterflooding, there are interesting new effects taking place under the pulsed conditions that need to be properly quantified for a realistic field deployment of the cyclic injection process. Two-phase immiscible pulsed flow experiments performed on homogenous packed glass beads cells are compared with flow behaviour under continuous injection. In the pulsed experiments, injection is switched on/off using a timing device in the pumping system. Symmetric cyclic periods and different injection rates were used in the study. Initially the dry packed cells were flushed with CO2 and saturated with water. This was followed by injection of oil up to leaving the cells at irreducible water saturation conditions. Then water was injected and the amount of produced fluids measured. Separate experiments under continuous and pulsed injection conditions with visual monitoring of fluid displacement were performed. It is found that the amount of oil recovered at intermediate stages (after breakthrough and less than 3 pore volumes of injected water) is larger for the pulsing mode. The final recovery for both injection processes is similar within the experimental error. In the pulsed experiments, during the off injection period, spontaneous fluid spreading was observed leading to smoother displacement fronts compared to continuous injection. Also, displacement fronts were found to be more stable under pulsed conditions. The study concludes that residual oil saturation under pulsed injection can be reached earlier than under continuous injection, a result very attractive for field application. Experimental findings of this work shed light in the design of cyclic injection processes. Introduction Cyclic water injection is being considered as a potential alternative to the inherent difficulties of waterflooding since it may lead to additional oil recovery. The process itself was proposed a few years ago, and has been tested successfully in some reservoirs in USA, Russia and China, where additional recoveries in the range 2–18% have been reported, with the additional benefit of a decrease in water cut levels. Even though the process is in principle very similar to waterflooding, there is still a lack of understanding on the role of certain parameters and operational variables. Among those we may cite: reservoir wettability initial oil and water saturation, saturation history effects, oil viscosity, cyclic period selection, and reservoir heterogeneity. Cyclic water injection refers to a process in which the injection rates are changed from high to low values and then back to high, in a periodic fashion, allowing the pressure maintenance support required in the water injection process. The cyclic periods are in the range of weeks to months, a different time scale from the so called pulsed pressure technique, where short pressure pulses are applied in time intervals of a few minutes. Several authors have simulated the cyclic injection process for a variety of operational conditions. However, only few experimental works have been reported quantifying the role different variables on the process, and to clearly establish the differences with continuous waterflooding. Visualization experiments are particularly appropriate to address such objectives allowing capturing fine details about the dynamics of flow displacement. After a literature review we present the methods and the properties of the porous media and fluids used in the experiments. The cyclic water injection process is compared with the results obtained in a conventional waterflooding experiment under conditions where the same amount of fluid is injected in each case. The effect of bead size, injection rate, oil viscosity, cyclic period is reported and analyzed. Displacement front stability is addressed in the discussion section.

The determination of the location of new wells in an oil reservoir is a complex problem that depends on reservoir and fluid properties, well and surface equipment specifications, geographical conditions and economic criteria. The final method to be used for field development should be based on the use of a reliable method for well location, oriented to reduce uncertainty, minimize costs and maximize the asset value.Reservoir simulation is recognised as one of the most reliable tools for defining the optimum production strategy. However, forecasting by reservoir simulation techniques bears risk as result of the uncertainty in the input data. The conventional approach to plan the number of production wells and their locations is by a tedious and costly trial and error process, where the final result depends on the ability of the reservoir engineer to fully understand the reservoir behaviour and the operational limits. Here, we present a new approach for optimal well location that was developed by combination of multiple realization and quality map methods. The proposed methodology starts from the static reservoir model in which main parameters are identified to reduce the number of simulation runs required for an optimized dynamic reservoir model by using the multiple realization approach. The study continues by determining the quality map for the reservoir, which is aimed to identify areas from where the hydrocarbon production is expected to reach a field maximum. This is performed by evaluating each possible well position at different locations up to finding the maximum production, without well interference or unphysical behaviour in well response. This approach was tested on the Maureen field, a North Sea reservoir, finding optimal well placement with an improved production. Numerical results obtained by applying the combined methodology provided larger hydrocarbon recovery from the field those results obtained by just using the two involved methods separately in 20 years of production. Predicted production values were significantly larger that those reported in actual field production. The methodology found spots where the forecasted production might be significantly larger if wells were located in coordinates other than some of the actual wells. Thus, the proposed method could be used as a tool to reduce uncertainty in development fields and an important technique towards an optimal asset management. 1. Introduction An optimal field development strategy should be based on the use of a reliable method for well location oriented to reduce uncertainty and minimize costs. It is known that the determination of the location of new wells is a complex problem that depends on reservoir and fluid properties, well and surface equipment specifications, geographical conditions, and economic criteria [1–2]. In general the determination of optimal well location can not be based on intuitive judgment only because engineering and geological variables have associated uncertainties and are normally highly correlated. Since well planning plays a significant role on return on investment, the decision on where to place a well within a reservoir brings challenges to drilling and reservoir engineers. These tasks are currently addressed with the use of new technological tools such as real time analysis and downhole tools which allows to improve accuracy and the ability to develop more reliable reservoir models using numerical simulators [3–5].

Most companies to date have adopted GHG emission targets in an effort to limit global warming well below 2 °C above pre-industrial levels, and 2020 estimations forecast a decrease of about 1/3 of emissions from O&G activities by 2050. It is also foreseen that regulations with economic impact on emissions from hydrocarbon production will be progressively adopted. This is triggering oil and gas (O&G) attention to find faster and economic ways to decarbonize while maintaining operational performance. Several types of initiatives are being considered including the reduction of flaring and venting, mitigation of methane leaks, increasing efficiency in energy use, use of renewable energy, and electrification of processes, in combination with the use of digital tools, and advanced monitoring to optimize performance. In this work we focus on a comparison of different decarbonization pathways for an offshore platform. It is assumed that the platform is already in place and in operation, and that the industry is already taking the required actions to reduce flaring and venting and mitigating methane leaks. The analysis starts by identifying the major contributors to the GHG emissions from the platform, which in this case is the power system, followed by fluid related processes like compression, separation, heating for transportation, and other associated operations. Public data from international energy agencies indicates that approximately 16 TWh/year is used to power offshore oil and gas platforms globally. We analyze the following five decarbonization pathways: a) improved energy use - decreasing the energy demand of the processes running on the platform and associated operations, b) increasing the efficiency of the power generation source, c) changing the nature of power source (renewable – wind, solar, wave, hybrid systems), d) implementing carbon capture units, and e) electrifying the facility (partial/full electrification cases). The analysis includes a comparison of promising concepts under each of the proposed pathways and summarize the challenges and opportunities offshore O&G operators have to implement them. Some of the alternatives are based on technology already used in the oil and gas industry, or in other industries, while in some others the technology is still under development. Reference is made to novel technology with potential to address the identified challenges for the different pathway options. We use a simplified metric system to highlight the most effective solutions according to location of the platform and its distance to shore. A discussion of what we will be needed for such pathways to be feasible is also presented.