Effectiveness Well Integrity Management for Casing Leak Detection Utilizing Temperature Profile in Offshore Oil Field

Offshore field started on operation to produce crude oil with 27 API° as sweet crude and sour crude with 32 API° since 1960. Large number of wells in offshore field revealed undesirable phenomena related to well integrity issues as potentially sustained pressure on several casing strings. Well integrity management emphasis on preventing well problems related to well safety and integrity such as casing leak, Sustained Casing Pressure (SCP), downhole safety valve (DHSV) failures. The direct impact from integrity management added great value in terms of decreasing in operating down time, improvement in well control and safety aspects, and reducing unplanned repair intervention. In addition, the loss of well integrity can cause major accidents with a severe risk to the personnel, asset and environment. The paper aims to illustrate a methodology results on applying effective well integrity monitoring techniques. A focus was made to improve monitoring well integrity through reviewing wellhead surface parameters, annulus sections pressure and downhole condition. In addition, the subject wells should be kept under close monitoring at a safe operable with an integral condition. Non-integral wells are common in aged wells, which are becoming a challenging issue to restore its integrity and operability especially for such aged completion. As a part of well integrity review, the concerns had been identified, investigated, and subsequently mitigations actions are recommended to restore the well integrity. Currently, it is confirmed that 25 oil producers with casing leak problems, which resulted to be converted from conventional completion to a slim hole with limited future accessblity. Based on lab reusltes and logging interpretations, it is indicated that the root cause of casing leaks is due to corrosive water flow from shallow aquifer formation. Therefore, an immediate remedial action is required to improve well construction. A successful worked over well with integrity issue as a casing leak was repaired by cement squeeze into across the corroded casing interval, which enhanced well integrity and restore well productivity. The resulted showed that tubing leaks encountered with well integrity due to sustained casing pressure. Therefore, the pressure on production casing can cause severe failure with catastrophic damage. The results also illustrated that a water flow through poor cement is a major cause of sustained casing pressure in the outer casing strings. The cause of pressure on production casing is generally easier to diagnose than that pressure on one of the outer casing strings. Challenges, methodology, work schedule, risk assessment, lesson learned and findings are included in this paper. The effective well integrity management resulted on great deal of benefits, which are related to securing wells, well operability, cost saving, and sustained maximum production target.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180065, “Thermal Effects on Subsea Wellhead Fatigue During Workover Operations,” by L. Cantinelli Sevillano, J. De Andrade, S. Sangesland, and M. Stanko, Norwegian University of Science and Technology, prepared for the 2016 SPE Bergen One Day Seminar, Bergen, Norway, 20 April. The paper has not been peer reviewed. Intervention and workover operations can significantly affect the structural integrity of subsea-wellhead systems with regard to their fatigue life. The increasing frequency of these operations has called for a renewed focus on the fatigue capacity of subsea wells, which has greatly improved the overall methodology used for wellhead-fatigue analysis. However, thermal effects along the well have yet to be incorporated. This paper analyzes wellhead-fatigue damage during a workover operation considering the thermal effects. Methodology The goal of the present study is to investigate the effects of the temperature variation along the well on wellhead-fatigue- damage rates by incorporating the temperature profiles of casing strings and cement into the fatigue-damage assessment of a particular wellhead system during a workover operation. In this study, a decoupled approach is proposed. The temperatures of riser, wellhead, and well components are calculated for different instants during the workover operation using a finite-difference method. Then, the temperature profiles for a given moment during the operation are incorporated into a 3D finite-element model (FEM) of the wellhead system. A structural analysis with focus on stresses at the fatigue hot spots is performed. Subsequently, a dynamic analysis of the riser provides the loading time history to which the wellhead is subjected; finally, combining the results of the structural analysis and the riser-response analysis enables the fatigue damage during the simulated operation to be estimated. The well adopted in this study follows a conventional subsea-completion program on the Norwegian continental shelf, with four casing strings and a production liner. Temperature Calculations. It is assumed that enough time has passed—between the shutting down of production and the moment that the workover riser is connected to the wellhead and the workover operation begins—for the temperature in the well to reach the undisturbed geothermal temperature profile. The workover operation simulated for temperature calculations consisted of injecting and circulating a heavy fluid until the hydrocarbons in the well were displaced. After that, circulation was stopped. The temperature profiles were calculated with a finite-difference method. During the simulated cold-fluid injection into the well, the deepest sections of the well are subjected to the largest temperature drop, given that the fluid is at lower temperature than the surrounding formation and well fluid, while the uppermost sections experience the effects of a circulating fluid at a higher temperature. Circulation was deemed to last approximately 3 hours.

Sand production is a problem that is often encountered in unconventional oil and gas exploitation and that is difficult to effectively solve. Accurate online monitoring of sand production is one of the keys to ensuring the safety and long-term production of oil wells as well as efficient production throughout the life cycle of production wells. This paper proposes a method for monitoring sand production in offshore oil wells that is based on the vibration response characteristics of sand-carrying fluid flow impinging on the pipe wall. This method uses acceleration sensors to obtain the weak vibration response characteristics of sand particles impinging on the pipe wall on a two-dimensional time-frequency plane. The time-frequency parameters are further optimized, and the ability to identify weakly excited vibration signals of sand particles in the fluid stream is enhanced. The difference between the impact response of the sand particles and the impact response of the fluid flow to the pipe wall is identified, and corresponding indoor verification experiments are carried out. Under different sand contents, particle sizes, and flow rates (sand content 0-2‰, sand particle size 96-212 μm, and flow velocity 1-3 m/s), the impact response frequency of sand particles to the pipe wall exhibits good consistency. The characteristic frequency band of sand impacting the pipe wall is 30-50 kHz. A statistical method is used to establish the response law of the noise signal of the fluid. Based on this knowledge, a real-time calculation model of sand production in offshore oil wells is constructed, and the effectiveness of this model is verified. Finally, a field test is carried out with a self-developed sand production signal dynamic time-frequency response software system on 4 wells of an oil production platform in the Bohai Sea. This system can effectively distinguish sand-producing wells from non-sand-producing wells. The dynamic time-frequency response, field test results, and actual laboratory results are consistent, verifying the effectiveness of the method proposed in this paper and further providing a theory for improving the effectiveness of the sand production monitoring method under complex multiphase flow conditions. This study also provides technical guidance for the industrial application of sand production monitoring devices in offshore oil wells.

Productivity losses of up to 90% had been observed in large offshore oil wells within less than a year of operation. Extensive investigation into possible formation damage and/or pore plugging, due to migration of formation fines (clay particles), had been conducted. Scaling was not considered because no formation brine had been produced. It was however observed that shallow acidizing procedures could restore the original productivity. Modeling studies were initiated with the aim of resolving this possible discrepancy, using the little known phenomenon that the water solubility in the oil is pressure dependent. Several brine samples from an aquifer below the oil bearing strata were studied. It was assumed that the composition of aquifer brine is representative of the residual brine saturation in the oil bearing formation. Then it was concluded that the scaling tendency1) of these brine samples had to be 1 (saturation equilibrium) under downhole conditions. Furthermore, modeling of the oil/brine equilibrium indicated that at a given temperature, the water content in the oil was shown to be a function of pressure – the higher the pressure, the lower the water content in the oil. As the oil was being produced, and a pressure gradient was established between the formation and the wellbore, the oil became richer in water at the expense of the brine. The brine in turn became more concentrated, hence oversaturated in minerals, whereupon scale deposition started. It was shown that relatively small amounts of formation brine can through scale precipitation significantly reduce oil flow through the formation around the wellbore.

Epoxy resin applications in oil and gas wells have significantly increased for remediation and sustained casing pressure mitigation because of its solids-free nature and excellent thermomechanical/bonding properties when used either as a single component or as a resin/cement-enhanced composite. Therefore, it is imperative to assess the formation and degradation of structures in cured epoxy resin at downhole temperatures, particularly because hydrocarbon production requires long-term wellbore integrity. Differential scanning calorimetry was used to determine the glass transition temperature ( $$T_{\mathrm{g}}$$ ) of the proposed resin system, and thermogravimetric analysis (TGA) was used to characterize the thermal degradation response by monitoring the resin specimens’ mass loss over time under controlled temperature ranging from 300 to $$680\,{^{\circ }}\hbox {F}$$ at atmospheric pressure. The thermal kinetic response based on TGA was then modeled using the Arrhenius equation to predict the resin lifetime under expected wellbore conditions. This work also presents a case study in which an epoxy resin–cement composite is used as an annular barricade to help prevent and reduce sustained casing pressure. The resin–cement composite was placed in the annular section between the 18 5/8- and 13 3/8-in. casing sections as a chemical packer tailored to improve bonding to steel pipe, along with optimizing its mechanical response to cyclic downhole loads, which resulted in no up-to-date sustained casing pressure. For a resin system subjected to downhole temperatures of $$263\,{^{\circ }}\hbox {F}$$ , the model predicts that reaching 10% mass loss by thermal degradation can take more than 160 years, which is beyond the operational life of the wells where the system is evaluated. This indicates that the investigated resin system provides long-term dependability that ultimately results in reduction of intervention/remediation costs, along with production maximization. Additionally, the resin mechanical properties were evaluated at different temperatures to assess their response to expected thermal loading, which resulted in competent barriers that can withstand the cyclic loads generated by continuous wellbore operations. Furthermore, cement bond log results further support the optimum annular integrity attained when utilizing a cement–resin composite as chemical packer for enhanced isolation and annular pressure buildup mitigation.

This paper presents the integration technology of workover equipment with production platform in offshore areas. The environmental conditions, the structure style and the characteristics of the platform are described in the paper. It belongs to the conventional jacket platform. The production control facilities, the work-over rig, triplex pump, watch cabin and living accommodation are installed on the deck, which are all movable and disassembling parts. They can be moved to other similar platforms to perform work-over or remedial work, which will reduce the platform operation cost. Although the cost of the platform is 30% higher than that of the conventional platform, it is 50% cheaper than that of a movable work-over platform and the construction method is simple. As a new type platform, it can be used for production in offshore areas with a water depth of 5-18 m. As more and more oil wells put into production in Chengdao island area, Shengli oilfield, Shandong province, oil testing water injection, well repair and work-over increases greatly. There are only two workover platforms in Shengli oilfield. Most oil testing and workover job is completed by the "Zuo Ye No.1" platform in the area where the water depth is more than 4m, it also need to perform the workover in offshore area in Liaohe oilfield. The "Zuo Ye No.2" platform can only work in the area where the water depth is less than 4m. Many work-over and remedial work especially oil testing after completion must be completed by drilling rig, which is a kind of waste to the drilling rig. The lack of the workover facility severely affected the production of offshore oilfield in Shengli and Bohai Bay. Movable production platform is not suitable for the exploitation of offshore oilfield because of its long design and construction period, high expenses, and high engineering difficulty. In addition, the towing and jacking are complicated and its workover costs are very high with an average price of 2.5 million Renminbi Yuan each time. The research on the integration technology of workover equipment with production platform in offshore field is started in 1997 so as to exploit effectively the marginal offshore field. For an offshore marginal field with a production less than 30-50 t/d per well or per well cluster in initial days and 10-20 t/d later, it is not commercial to use current conventional production technology. It is important for the exploitation of offshore oilfield in Shengli and Bohai Bay to find out a new kind of platform. The platform can meet production requirements not only at present but also in the future, be competent to not only production but also work-over, can not only fixed on the production and workover platform but also move flexibly among production platforms.

The objective of this paper is to show the value of using real time remote monitoring system (Automation) in offshore wells and to show a case study from Company for how we successfully used the system to detect well anomalies in real time and perform the suitable corrective action to optimize the well production and maximize well recovery with minimum man-hours. Our company is a leading Egyptian petroleum company with + 200 oil producers on 70 offshore platform; 27 % of platforms include automation system, in platforms without automation system we detect wells problems by performing periodic site visits and check the operating parameters per well., normally it take weeks between two successive platform visits. For platforms with automation system, we install pressure sensors on WH, Manifold, and casing head and temperature sensor on WH., The data being transferred from sensors to office instantaneously, which we successfully made use of, to respond quickly to the problems and achieved maximum well recovery. The offshore oil producer well J-100 was drilled and put on production on Nov. 2015, the well was producing naturally from the attic of the reservoir, it was a mandatory to control the production rate to keep the well producing beyond the calculated critical production rate to avoid water coning. After a while of putting the well on production, well sensors showed several successive abnormal changes in readings which had been captured in real time with the help of automation system, and with data analyzing we found the causes of each phenomena every time (like loading up, a problem in the production choke, etc.) and we succeeded to prepare the action plan, and perform the scope of work as soon as possible. Without the automation system, it would take weeks to detect the problem based on the site visits plan. However, installing the automation system will enhance the response efficiency by saving the time required for problem detection, and improving the quality, density and accuracy of well data. In addition, it will decrease the losses in production rate, and maximize the recovery by optimizing the production rate based on the field depletion plan. In summary, this paper discussing a case study for the value of using real time remote monitoring systems in offshore fields and we used this case to highlight the need to expand the system to include more wells in our field to maximize the field recovery and add considerable benefit to the business.

Oil and gas wells with compromised integrity are a concern because they can potentially leak hydrocarbons or other fluids into groundwater and/or the atmosphere. Most states in the United States require some form of integrity testing, but few jurisdictions mandate widespread testing and open reporting on a scale informative for leakage risk assessment. In this study, we searched 33 US state oil and gas regulatory agency databases and identified records useful for evaluating well integrity in Colorado, New Mexico, and Pennsylvania. In total, we compiled 474,621 testing records from 105,031 wells across these states into a uniform dataset. We found that 14.1% of wells tested prior to 2018 in Pennsylvania exhibited sustained casing pressure (SCP) or casing vent flow (CVF)-two indicators of compromised well integrity. Data from different hydrocarbon-producing regions within Colorado and New Mexico revealed a wider range (0.3 to 26.5%) of SCP and/or CVF occurrence than previously reported, highlighting the need to better understand regional trends in well integrity. Directional wells were more likely to exhibit SCP and/or CVF than vertical wells in Colorado and Pennsylvania, and their installation corresponded with statewide increases in SCP and/or CVF occurrence in Colorado (2005 to 2009) and Pennsylvania (2007 to 2011). Testing the ground around wells for indicators of gas leakage is not a widespread practice in the states considered. However, 3.0% of Colorado wells tested and 0.1% of New Mexico wells tested exhibited a degree of SCP sufficient to potentially induce leakage outside the well.

ABSTRACT: Shale oil in northeast China is about to enter the stage of large-scale hydraulic fracturing. Cement sheath integrity must be ensured for horizontal shale oil wells. In this paper, the mechanical parameters of cement sheath are measured. A numerical model of casing - cement sheath - formation assembly is established to analyze the stress law of cement sheath. The integrity of the cement sheath is analyzed. The results show that the elastic modulus of cement is 6 GPa and the Poisson’s ratio is 0.17. The compressive strength and tensile strength of cement after cyclic loading are 90MPa and 7.5mpa ~ 11.25mpa respectively. The maximum radial stress of cement sheath increases with the increase of fracturing pressure, the decrease of displacement, and the increase of elastic modulus. The maximum tangential stress of cement sheath increases with the increase of fracturing pressure and elastic modulus of cement. The tensile strength of cement sheath cannot meet hydraulic fracturing requirements. The elastic modulus of cement should be reduced to 4 GPa or the tensile strength should be increased to be higher than 15 MPa. This study would guide the shale oil wells in northeast China. 1. INTRODUCTION As hydraulic fracturing technology matures and international oil prices recover, more and more unconventional oil and gas resources are being developed, such as shale gas, conglomerate reservoirs, and shale oil. In particular, shale oil resources are becoming a new direction of exploration and development of unconventional oil and gas resources in China. Shale oil has been developed scaled in Jimsar block, in Inner Mongolia, and Tianjin district. At the same time, shale oil resources have been successfully explored in northeast China and will soon enter the stage of large-scale development. Based on the development experience of shale gas and other unconventional oil and gas resources over the past few years, casing deformation and sustained casing pressure are the most common problems in horizontal wells during multistage fracturing (Adams, 2017; Atkinson, 2020; Chaojie Zhao, 2020; Xi Yan, 2021.). Well integrity issues have a significant impact on the safety and production of horizontal wells. Fig. 1 shows the casing deformation logging results of Wel-Wei204H39-6 in the Weiyuan block and Well-JHW033 in Jimsar Block, Xinjiang respectively. Logging results showed casing deformation in both wells. One of the wells is a shale gas horizontal well and the other is a shale oil horizontal well. Thus, shale oil wells face the same well integrity issues as shale gas wells.

The Longwangmiao (referred to as LM) gas field in southwest China has characteristics of high temperature (144~156 °C), high pressure(75~76 MPa), and high production rate (70~100×104 m3/d). Serious well integrity problems were encountered in the development process; 21% of 56 wells were subjected to sustained casing pressure (SCP)(≥20 MPa). Downhole leak detection logs indicated the main cause was tubing connection leakage at a depth range of 0~2400 m. Wellhead growth was present in 33 wells and 4 wells exhibited gas leakage through wellhead valves. Theoretical analysis and field tests were conducted to investigate and manage well integrity problems. A method to calculate the allowable pressure for different annuli was proposed based on string strength analysis, and downhole leak detection was conducted using ultrasonic leak detection method. A multi-string mechanical model to predict wellhead growth was established and the threshold values were calculated under different gas rates. According to the structure of wellhead, a method based on ultrasonic phased array to detect the work state of the wellhead was adopted, which measured the actual thickness of key valves to evaluate service life. For wells with SCP, the allowable pressure for different annuli was calculated and the pressure management charts were drawn and all wells were in steady production. Downhole leak detection showed that SCP in the A annulus (annulus between the tubing and production casing) was caused by connection leakage of tubing. In newly completed wells, a premium connection was adopted based on tests under cyclic structural and environmental thermal loads that the connections may encounter at various production phases, and the total ratio of SCP in newly completed wells decreased by 31.4%. Wellhead growth was predicted and compared with actual data, which showed an increase in average accuracy of 20~30% compared to the results from the WellCAT software. Sensitivity analysis revealed that the length of un-cemented casing and the production rate were the critical factors affecting the wellhead growth. The valve leakage of FF level material wellhead was caused due to corrosion after the removal of the coating, and no leakage was detected in the HH level material wellhead. Thickness survey showed that the average reduction was 0.085 mm~0.23 mm for HH wellhead, and 1.12 mm~2.24 mm for FF wellhead.

Corrosion is a common problem in oil, gas, and water wells. It has ability to cease the deliverability of oil wells and has significantly affected ultimate recovery from existing oil fields. Due to the limitation of continuous downhole corrosion monitoring or use of corrosion logging tools which are not continuous determination of precise rate of corrosion becomes extremely challenging. To overcome this shortcoming, a novel downhole corrosion system has been devised. This paper outlines a strategy for the successful implementation of a distinctive approach to measure downhole corrosion and scale using a mechanical cylindrical coupon system with noteworthy enhancement in the life of completions jewelry at one of the largest onshore oilfields. Methods, Procedures, Process This rig-less technique incorporates introduction of downhole corrosion coupon which is installed inside an exclusively designed corrosion monitoring valve or gauge hanger with lock mandrel or high expansion gauge hanger with non-explosive setting tool. These distinctive systems are developed not only to overpower the technological drawbacks of conventional systems, but also accurately measure downhole corrosion and scale in oil, gas and water wells which are completed with gas lift completions, nipple less completion or completions with profile nipples to transform well lifecycle. Formulation of well selection criteria, individual well sampling and assessment, proper data gathering, data analysis, application methodology and custom-made design of well programs have made it possible to operate wells under safe condition and are capable to function continuously to achieve the targeted production requirements. Results, Observations, Conclusions A pilot project on nine wells for a major operator in the middle east exhibited a significant improvement to measure downhole corrosion rates and enhance well life by designing an effective chemical treatment program to mitigate downhole issues. This reduced the frequency of workovers worth savings of $50M and eradicated downtime for production operations. Application of this technology has broken the barrier in evaluation of these wells and provides an effective means of diagnosing the wells with well integrity issues beyond the capability of standard corrosion and scale monitoring methods. It is a cost-effective technology to identify downhole integrity issues and enhance the field value from existing wells. Additive Information This paper considers selection methodology and scenarios that help to estimate potential well integrity challenges and formulate downhole chemical treatment program for elevation of downhole tubulars run life and recommends suitable actions which allow well integrity engineers to take timely actions for sustaining production from oil and gas wells. The paper will also discuss the role of this technology in the overall well construction workflow. With the increased complexity of mature fields, each next step to improve recovery comes with increased cost. Therefore, novel horizons of affordable technology will play a pivotal role to maximize economic recovery and meet rising demand in the current business environment.

Numerical models and laboratory studies have been performed by other investigators to define the impact of various perforation parameters on well productivity. Field verification of these findings is difficult due to uncontrolled factors such as charge performance, drilling invasion, and reservoir quality. Using information from Prudhoe Bay, a study of perforation parameters affecting well productivity was undertaken in an effort to identify the most significant perforation variables in terms of initial and long term well performance. Findings from the study of field data verifies that perforation penetration is the most significant factor affecting well performance. Wells perforated with deep penetrating casing guns have lower drawdowns and significantly lower decline rates than wells perforated with through tubing guns. The high decline rates at Prudhoe Bay are a result of calcium carbonate scale buildup, which is exacerbated by perforations of poor quality. The data also suggests that 0° gun phasing is comparable to other phasing when perforating in deviated, large diameter well bores.

This work presents a methodology for predicting temperature and pressure profiles in oil wells that employ the artificial lift technique through gas-lift. When the reservoir pressure is not sufficient to bring the oil to the surface or when increasing production efficiency is desired, artificial lift techniques are employed. The injection of gas (gas-lift) is one of the most commonly used techniques. In the oil and gas industry, the accurate prediction of temperature profiles during various operations is crucial for ensuring well integrity. These profiles serve as inputs for calculating variations in annular pressures, casing stress, corrosion rates, and other critical parameters. However, calculating these profiles is challenging, requiring data on the well's underground structure, simultaneous resolution of the differential equations governing heat transfer phenomena in the structure, and modeling the hydrodynamic behavior of fluids. In wells where production operations are carried out using gas-lift, the complexity is even greater because the annular fluid, previously static, now circulates downward. This fact increases the number of equations to be solved and the number of fluids to be modeled. Thus, the development of strategies for obtaining these profiles is justified. To achieve the proposed objective, the methodology adopted in this work is based on three main steps: a) description of the mathematical formulation of the problem, considering the energy, momentum, and mass balance in the flow of both the produced fluid and the injected fluid; b) development of a numerical strategy enabling the simultaneous solution of the equations formulated in the previous step, thus allowing the determination of temperature and pressure profiles in the well; and c) verification of the strategy by comparing the results obtained using the procedure described in this work with thermal profiles from wells reported in the literature. The main contribution of this work is to enable the prediction of thermal profiles in oil wells in production operations with artificial lift by gas injection, allowing these profiles to be used in the design and monitoring of wells, thereby adding safety and efficiency to the operation.

This paper presents methods developed to enable the lifting and producing of low-gravity, high-viscosity crude from offshore fields. Relative advantages and disadvantages of several lifting, treating, and transportation methods are discussed. The paper also reviews actual experiences with heavy-oil production offshore southern California, as well as plans for development of newly discovered heavy-oil fields in the Santa Maria basin offshore central California and offshore Sicily in the Mediterranean Sea.

In the last years, the use of FPSOs is becoming a widespread technology because it is a practical and cheap system for the exploitation of small oilfields or deep water oil wells, i.e. oilfields for which the installation of pipelines is too expensive. Recently, growing attention has been devoted to the advanced design of vessels able to operate effectively even when the system is subject to abrupt movements. The study of the behavior of process fluids (gases and liquids) and their mutual system is subject to abrupt movements. The study of the behavior of process fluids (gases and liquids) and their mutual Fluid Dynamics (CFD) techniques. In this paper, a fluid dynamic model of a FPSO separator is developed using a CFD methodology. This model is able to predict the behavior of the fluid and of their interfaces within the separators to be installed on FPSOs. Several simulations were carried out to study the behavior of the fluids and the efficiency of two vessel types (reboiler and surge vessel). The vessels are subjected to the forcing conditions typical of an ocean storm, i.e. surge, sway, heave accelerations and roll, pitch and yaw rotations, gathered from real historical data. Transient simulations were carried out applying time-varying accelerations to the vessel. The methodology is described in order to give general guidelines for the FPSO simulations. The main technical contributions of this study are:the understanding of the behavior of the liquid in the separator mounted on FPSOs in different storm conditions;the validations of FPSO separator design to assure their functionality even during heavy storms;the A development of a numerical methodology to implement complex CFD simulations in the presence of time-varying boundary conditions which models the effect of sea movements on on-board ship devices. Introduction The ever increasing research regarding new technologies for the exploitations of off-shore oil wells has led to the creation of FPSO in the 1970s. This technology allows the exploitation of oil wells for which the installation of an oil platform and pipeline is too expensive, is not technically advantageous or, in the case where hydrocarbons must be stored, until it can be uploaded onto a tanker or transported through a pipeline. The FPSOs can be either decommissioned tankers or purpose-built ships used for receiving, processing and storing the hydrocarbons produced by nearby platforms or subsea wells. Several separators and oil treatment systems are installed on an FPSO. These systems are intended to separate water from oil and gas extracted and, subsequently, to process them. Once processed, the fluids are stored awaiting to be transferred. The most common technique to separate oil, water and gas is the use of large gravity-based vessels (separators). The FPSOs are ships that perform their functions by being moored permanently so the FPSOs and all the systems installed on-board are subjected to wave motion. These movements, that can be very violent i.e. during an ocean thunderstorm, cause sloshing within the vessels. The slosh motion can reduce the separator's efficiency and cause great damage to the structure. It is therefore necessary to study the behavior of the fluids within the separators. The design verification of the separators to be installed on FPSO can be carried out by numerical simulations. The numerical simulations are a cheap instrument to verify the performance of the separators and the design choices without the need to create a prototype.