Heavy oil reservoirs are known for their low recovery factors. Additional energy consumption, special operations, and enhanced oil recovery (EOR) techniques are required for production due to high viscosities. Also, unfavorable water-oil mobility ratio is a serious problem when waterflooding (WF) is implemented, usually causing early breakthrough and higher water cut. Developing and managing a production strategy through a comprehensive decision-making procedure is also complex due to the high number of variables, uncertainties, and physical phenomena involved. Polymer flooding (PF) is an EOR method that can be applied to heavy oil reservoirs to improve field performance by producing more oil and reducing water production. This improvement is achieved through the increase in water viscosity caused by the injection of polymers, thus reducing water-oil mobility ratio, and obtaining better oil displacement efficiency. In the case of intelligent wells (IW) equipped with Inflow Control Valves (ICVs), the WF limitations can be mitigated by controlling multiple production/injection zones, increasing oil production, and maintaining the reservoir pressure. This work aims to perform a nominal production strategy optimization to develop and manage a heavy oil reservoir considering PF as a production strategy (using conventional wells only) and comparing it to waterflooding with ICVs (WF+ICV) for the same case. A complete methodology to optimize the design and control variables is applied to the strategies by using model-based reservoir simulation. The objective function (OF) is the Net Present Value (NPV), this study case is named EPIC001, which has a 13° API heavy oil reservoir that represents part of a Brazilian offshore field. We have applied a specific methodology to optimize the PF strategy for a heavy oil reservoir of a nominal case which is practical and clear in the selection and comparison of strategies for similar cases. The results found PF strategy is the more suitable for the case, obtaining an NPV that is 21% higher than WF+ICV. Injecting polymers in the earlier stages of the life cycle at lower polymer concentration rendered PF with greater oil recovery (+13%) with a better efficiency in management of water and polymers, therefore surpassing the good ICV management from WF+ICV.
Paraffin buildup, along with other production debris, poses a significant challenge to subsea production flowlines, especially in cold, deepwater environments where extended subsea tiebacks cause crude oil to lose heat to surrounding seawater (Oliveira et al., 2018; Oliveira et al., 2024) This thermal decline can drop the oil's temperature below the critical temperature of deposition (CTD), thus, leading to paraffin accumulation. A prime example of this phenomenon is the Petrobras-operated X field off the Brazilian coast, which exemplifies the complexities of deepwater crude oil production. This manuscript details a methodology used to melt and remove paraffin buildup efficiently in a restricted-access area of the X field's surface production flowline. Using a quite simple innovative in-house solution, the paraffin deposit was melted from top to bottom and successfully removed. This represents a groundbreaking achievement, as it is the first documented instance of using the combination of dry-steam and high-pressure cleaning hoses to remove paraffin blockages in a Petrobras-operated field.
The natural gas stream is produced alongside entrapped water, and there is need to remove this entrapped water to attain hydrocarbon dew point specification. This study investigates the effect of TEG (Triethylene Glycol) recirculation rate on the water content of dehydrated natural gas, focusing on optimizing the performance, energy efficiency, and cost-effectiveness of TEG-based glycol dehydrators. That increase in TEG recirculation rate yields decrease in water content of dehydrated gas until reaching a certain TEG rate. The recommended TEG-feed gas flow rate ratio is 164 gallons TEG/MMSCF. TEG purity impacts water removal efficiency, regenerator reboiler, duty, and temperature. Increase in number of absorber stagers reduces the water content of the dehydrated gas. From the optimization study, the optimal TEG flow was determined to be 71.75 BPD (barrels of oil per day) with a purity of 0.9898, achieving the desired moisture content of 6.981 lb/MMSCF. The phase envelope and hydrate formation analysis confirmed the effectiveness of the dehydration process, ensuring gas flow even at low ambient temperatures.
The reduction of drilling time due to the addition of new equipment, tools, and technologies has reduced drilling costs significantly, leading to the production of hydrocarbons at competitive costs. Observations from project engineers are at the base of conventional well planning, using information from offset wells to estimate the costs in future wells. This works uses a statistical approach to evaluate historical drilling costs of oil and gas wells to reduce the influence of personal decisions and provide the staff with more precise data-driven cost estimations. Initially, to establish a strong foundation on the drilling cost and time estimation, we review general cost analysis concepts to estimate drilling cost and drilling time using field data to show cost trends for various depths. The study of Canto do Amaro and Estreito fields cases demonstrate the benefits of this approach in the development of new drilling projects. The solution proposed supports accurate cost planning, considering that the improvement of an operational window provides a better understanding of the cost projection when compared to traditional cost estimation.
Crude oil salinity on production platforms is measured for sale typically using ASTM D3230 (conductometry) or ASTM D6470 (potentiometry). Conductivity-based measurements employ a salimeter, which has a maximum limit of 500 ppm. However, salt levels in oil from primary separation often exceed this threshold. This work aims to adapt the salimeter method, by adjusting the oil sample size, to enable measurements above 500 ppm. Laboratory tests were carried out on an offshore production platform in a Brazilian post-salt field, using heavy crude oil samples from the platform’s primary separation. Each sample was analyzed using both standard and modified tests. Statistical comparisons, including Yuen’s robust t-test with bootstrap resampling, were applied. Results show that modified test produced values statistically equivalent to the standard test, with only slight variability increases from outliers. The modified method proposed provides a practical and reliable option for addressing high-salinity scenarios where conventional equipment reach its measurement limits.
