Offshore Petroleum Production Research Articles

Carboxylic Acids in the Synthesis of Chemicals for Addressing Flow Assurance Challenges in Offshore Petroleum Production

Abstract: Flow assurance encompasses the technical challenges of transporting hydrocarbon mixtures from the reservoir to the platform and refineries. Challenges in flow assurance include gas hydrate plugs, deposition of paraffin wax, asphaltenes, naphthenates, scale, and corrosion. Managing these deposits incurs high costs due to production interruptions and remediation operations like pigging, solvent injection, acid dissolutions, and thermal treatments. Therefore, prevention methods, such as the use of chemicals that inhibit deposit formation, are preferred. This review consolidates scientific works highlighting the role of carboxylic acids in the synthesis of chemicals for addressing flow assurance challenges as starting materials or final products for direct use. These organic compounds are already employed for the mild remediation of scale and naphthenate deposits and inhibiting gas hydrate, paraffin wax, asphaltene, scale deposits, and corrosion. Moreover, they play a crucial role in developing green flow assurance challenges inhibitors, given that some, like fatty acids, amino acids, and aromatic carboxylic acids, can be derived from natural sources. The presence of the carboxylic acid group in polymers and biopolymers is also essential for the effectiveness of these products as inhibitors. The literature further suggests that carboxylic acids will play a key role in the future development of simultaneous gas hydrate, corrosion, and scale inhibitors.

O3PO: A domain ontology for offshore petroleum production plants

The challenge of integrating data from many data sources has persisted as an issue in several industry areas. With the evolution of technology in the upstream petroleum sector (i.e., exploration and production), the petroleum business must contend with technological silos from diverse service providers and suffers from the associated waste of time to locate data and information throughout siloed databases. Based on a thorough compilation of industry-oriented requirements in the form of use cases and competency questions, this document defines a domain ontology for defining entities in offshore petroleum production plants. The objective is to develop a uniform and clearly defined reference vocabulary to aid engineers and information technology professionals in labeling and relating production plant monitoring, simulation measures, and facilities. BFO is the top-level ontology, while GeoCore and a continuing version of the core ontology developed by the Industry Ontology Foundry (IOF) configure the middle-level ontologies. We have studied and combined several other resources to build the ontology, such as glossaries from the industry and related ontologies. The research resulted in a well-founded domain ontology that provides universals, defined classes, and relations that can be useful in several types of applications in the domain. We have demonstrated the utility of the ontology within an actual scenario in an offshore petroleum field in Brazil, where we conceived and applied the domain ontology. This study is a component of the PeTWIN project,22Petwin is an academic cooperation between UFRGS, UiO, and Libra, Equinor, and Shell companies (www.petwin.org). which looks at the best approaches for creating digital twins of offshore petroleum plants.

EMULSIONS IN OFFSHORE PETROLEUM PRODUCTION: STABILITY AND FLOW ASSURANCE

Emulsions represent a relevant concern in offshore petroleum production. Besides the topside oil-water separation, other topics related to flow assurance have received increasing attention from industry and academy. This paper reviews petroleum emulsions and their aspects that impact offshore petroleum production. Topics discussed in this review include emulsion stability, emulsion samples, and flow assurance related topics like pressure-drop, wax, and hydrates. The knowledge around petroleum emulsions has reached a fair level in terms of stabilization and destabilization mechanisms. Nevertheless, challenges, such as understanding the emulsion formation in presence of pressurized gas and comprehending how emulsions affect the multiphase flow behavior as well as the precipitation of solids, remain.

A simplified economic model predictive control for a gas lifted oil production network based on modifier adaptation

We propose a novel simplified economic model predictive controller (EMPC) for supervisory control of an offshore petroleum production network composed of two wells, a riser, and a separator. The proposed controller uses a gradient-and-modifier-based methodology to mimic a nonlinear EMPC (it considers a nonlinear process model and cost function), while only solving quadratic programming. We alter the modifier adaptation to depend on an estimator and employ slack variables to improve feasibility. Tips for appropriate design, to improve stability and robustness, are presented. Since the tested facility is subject to multiple disturbances, we also use a regulatory controller to stabilize the system. Finally, we compare our method to a linear EMPC and self-optimizing control in various scenarios considering disturbances, noise, and model inconsistencies. The proposed controller always tends towards the economic optimal point, presenting similar nominal performance as the others advanced controllers and better robustness.

Impact of flow field resolution on produced water transport in Lagrangian and Eulerian models

During offshore petroleum production, large volumes of produced water are continuously discharged. The environmental impact from such discharges is typically assessed with numerical models, which simulate the transport and dilution of the produced water plume in order to predict environmental concentrations of its chemical constituents. In this study we investigate the effects of model resolution (800 m and 4 km) on produced water dispersion. We also compare two different types of models, a Lagrangian particle model, and an Eulerian grid-based ocean model to assess the Eulerian consistency of the Lagrangian model. We consider a point source off the coast of mid-Norway, during two different seasons (winter and spring). In general, the two models are in reasonable agreement. We find a substantial difference in tracer distribution and concentrations between the two resolutions, and to a lesser extent between seasons; in particular, the 800 m model shows lower concentrations along the coast.

Severe slugging flow identification from topological indicators

In this work, topological data analysis is used to identify the onset of severe slug flow in offshore petroleum production systems. Severe slugging is a multiphase flow regime known to be very inefficient and potentially harmful to process equipment and it is characterized by large oscillations in the production fluid pressure. Time series from pressure sensors in subsea oil wells are processed by means of Takens embedding to produce point clouds of data. Embedded sensor data is then analyzed using persistent homology to obtain topological indicators capable of revealing the occurrence of severe slugging in a condition-based monitoring approach. A large dataset of well events consisting of both real and simulated data is used to demonstrate the possibilty of authomatizing severe slugging detection from live data via topological data analysis. Methods based on persistence diagrams are shown to accurately identify severe slugging and to classify different flow regimes from pressure signals of producing wells with supervised machine learning.

Continuous Distillation

In the present study, a Distillation process separate two components namely Toluene and Benzene is being performed. The distillation experiments are carried out on the DWSIM software. Where we learn to create a material stream in DWSIM. The types of distillation performed on DWSIM include Shortcut distillation, Rigorous Distillation. Process equipment includes suction scrubber compressor discharge cooler mixture and value the major difference between the booster compression and sales as compression are the operating pressure temperature and chemical composition of gas production the flow sheet of sale gas compression and export in DWISM. We specifically focus on the simulation of chemical process using the modelling software to evaluate thermal and chemical behaviour of the system which uses the chemical processes related to offshore petroleum production facilities as an example to demonstrate the software capabilities of DWSIM.[1].

Computational fluid dynamic modeling of methane hydrate formation in a subsea jumper

Gas hydrate in subsea pipelines is a serious flow assurance issue that may impose operational challenges to offshore petroleum production and transportation. The effects of fluid properties on hydrate formation in complex geometries such as jumpers are not fully understood. This study aims to assess hydrate formation in the jumper for the water-methane system using the Eulerian multiphase flow model through employing computational fluid dynamic (CFD) software (STAR CCM+). The numerical model is developed through consideration of transport phenomena equations, including conservation of mass, momentum, and energy in which mass transfer, hydrate reaction kinetics model, and heat of hydrate formation are incorporated in the multiphase flow equations in the form of source terms in the CFD software. In this study, first, the hydrate mass fraction for the fluid velocity of 5 m/s with an inlet temperature of 7 °C and a gas volume fraction of 0.2 is calculated. The sensitivity analysis is then performed considering the influences of changes in the inlet fluid velocity, gas volume fraction, inlet temperature, and subcooling on the hydrate formation. The results reveal that the developed CFD model is capable of predicting hydrate formation behaviors in the jumper with acceptable precision. An increase in the liquid inlet velocity and gas inlet temperature lowers the amount of hydrate formed in the jumper. In contrast, an increase in the subcooling and gas volume fraction leads to more hydrate formation. The proposed CFD model can be successfully used to simulate hydrate formation in pipelines under various process and thermodynamic conditions so that it can help to find reliable/effective methods for hydrate management.

Experiments and mechanistic modeling of viscosity effect on a multistage ESP performance under viscous fluid flow

Assembled in series with multistage, Electrical Submersible Pumps (ESP) are widely used in offshore petroleum production due to the high production rate and efficiency. The hydraulic performance of ESPs is subjected to the fluid viscosity. High oil viscosity leads to the degradation of ESP boosting pressure compared to the catalog curves under water flow. In this paper, the influence of fluid viscosity on the performance of a 14-stage radial-type ESP under varying operational conditions, e.g. rotational speeds 1800–3500 r/min, viscosities 25–520 cP, was investigated. Numerical simulations were conducted on the same ESP model using a commercial Computational Fluid Dynamics (CFD) software. The simulated average pump head is comparable to the corresponding experimental data under different viscosities and rotational speeds with less than ±20% prediction error. A mechanistic model accounting for the viscosity effect on ESP boosting pressure is proposed based on the Euler head in a centrifugal pump. A conceptual best-match flowrate QBM is introduced, at which the impeller outlet flow direction matches the designed flow direction. The recirculation losses caused by the mismatch of velocity triangles and other head losses resulted from the flow direction change, friction loss and leakage flow etc., are included in the model. The comparison of model predicted pump head versus experimental measurements under viscous fluid flow conditions demonstrates good agreement. The overall prediction error is less than ±10%.

Numerical Investigation on Hydrodynamic Characteristics of Immersed Buoyant Platform

The Next Generation Subsea Production System (NextGen SPS) is considered as a competitive alternative system used for offshore petroleum production in ultra-deep sea based on the artificial seabed technology. The Immersed Buoyant Platform (IBP), which is located at a constant depth below the free surface of the water to minimize wave loading, provides a buoyant stable platform for supporting the well completion equipment. Therefore, the hydrodynamic characteristics of IBP in the currents play an essential role in determining the global responses of NextGen SPS. In this paper, aiming at acquiring an optimum structural form of IBP, the hydrodynamic characteristics of the flow past the cylindrical IBP with different height-to-diameter ratios are systematically investigated by use of the large eddy simulation (LES) approach. The simulations with fifteen different height-to-diameter ratios (H/D) are investigated. The Reynolds numbers are ranged from 0.94×106 to 3.45×106. It can be verified that the separated fluid reattaches on the surface of the cylinder when the aspect ratio is between 0.1 and 0.4. Due to the specific shape ratio and obvious 3D effect of the cylindrical IBP, no significant vortex shedding has been clearly observed when the aspect ratio is between 0.1 and 0.4. In the case of 0.4≤H/D≤5.0, a series of regular and alternating vortex street shedding appear behind the circular cylinder. The simulation results also show that the recirculation region length behind the cylindrical IBP can be significantly reduced with the decreasing aspect ratio. It can be concluded that the cylindrical IBP performs the best hydrodynamic characteristics when the aspect ratio is between 0.3 and 0.4. The research findings will be of great significance to providing valuable reference and foundation to determine the optimum form of underwater structures, such as the buoyancy cans of the hybrid riser system.

Kinetic and rheological investigation of cyclopentane hydrate formation in waxy water-in-oil emulsions

Hydrates and waxes are supposed to coexist in the deep-water pipelines under suitable conditions of low temperature and high pressure. Understanding the effect of precipitated wax crystals on hydrate formation and rheological properties of hydrate slurry is crucial to the flow assurance in offshore petroleum production. In this work, a stress-controlled rheometer was used to carry out the rheological experiments for investigating the impact of wax crystals on hydrate formation and yield property of hydrate slurry. The effects of wax content and water cut on cyclopentane (CP) hydrate nucleation and growth were investigated in terms of the measured viscosity data. Log-normal distribution could well fit the probability density histogram of CP hydrate critical time. The logarithmic mean values of CP hydrate critical time decreased with increasing water cut but increased with increasing wax content in water-in-oil (w/o) emulsions. Semi-empirical models were proposed to describe the inhibitory effect of wax crystals on CP hydrate nucleation kinetics by considering the inhibition of mass transfer based on the Freundlich and Langmuir adsorption functions, respectively. Hydrate slurry viscosity rate showed the two-stage characteristics in wax-free w/o emulsions, while four stages could be clearly observed in waxy w/o emulsions. The maximum values of hydrate slurry viscosity rate and calculated hydrate effective volume fraction decreased with increasing wax content. Hydrate growth time was gradually extended as wax content increased. Furthermore, the measured yield stress and yield strain increased with increasing wax content at different water cuts, which was associated with the multiple effect of capillary bridge between hydrate particles, spatial network of wax crystals and coalescence of water droplets. At last, compared to the stress ramp rate, the influence of annealing time on yield stress was more significant.

Pressure Drop of Horizontal Air–Water Slug Flow in Different Configurations of Corrugated Pipes

Abstract Corrugated pipes (CP) have regularly shaped and spaced cavities on their internal walls that can induce dynamic changes in the flow, such as increased pressure drops. Offshore petroleum production pipelines are an example of an industrial application of CPs, known as flexible lines. Slug flow is the most challenging flow pattern in those lines due to its complex hydrodynamics. A number of previous studies proposed correlations to predict the two-phase flow pressure drops in smooth pipes (SPs). However, limited researches have evaluated the pressure drops associated with liquid–gas slug flow in CPs. In this work, experiments to analyze the pressure drops in horizontal air–water slug flow under different configurations of CPs were carried out. The tests were performed in three different CP internal diameters (IDs) (26, 40, and 50 mm) with different cavity widths (1.2, 1.6, and 2.0 mm). The effects of the internal diameters and the cavity widths on the pressure drops associated with slug flow were analyzed. Results demonstrated that the pressure drops increase with increasing cavity widths. The experimental data were fitted and a pressure drop correlation using the concept of multiplier factor was proposed. Comparisons between predictions and the experimental data proved to be within ±10% accuracy.

Comparative assessment of advanced power generation and carbon sequestration plants on offshore petroleum platforms

On conventional offshore petroleum platforms, the combined heat and power production (CHP) currently depends on simple cycle gas turbine systems (SCGT) that operate at lower efficiency and increased environmental impact compared to modern onshore thermoelectric plants. Additionally, the reduced space and the limited weight budget on offshore platforms have discouraged operators from integrating more efficient, but also bulkier cogeneration cycles (e.g. combined cycles). In spite of these circumstances, more stringent environmental regulations of offshore oil and gas activities have progressively led to a renewed interest in the integration of advanced cogeneration systems, together with either customary or unconventional carbon capture approaches, to maintain both higher power generation efficiencies and reduced CO2 emissions. Thus, in this paper, it is evidenced how advanced gas turbine concepts are promising technologies for maintaining or even increasing efficiency, while facilitating the capture rate of CO2 produced, either for geological storage or enhanced oil recovery. Despite the profuse research works on onshore applications, advanced cogeneration and carbon capture systems have been barely studied in the context of supplying power to offshore petroleum platforms. Accordingly, the performance of a conventional offshore petroleum production platform (without carbon capture system) is compared to other configurations, based on either an amine-based chemical absorption system or oxyfuel combustion concepts ( S-Graz and Allam cycles) for CO2 capture purposes. Since the original power and heat requirements of the processing platform must remain satisfied, an energy integration analysis is performed to determine the waste heat recovery opportunities. Additionally, the exergy method helps quantifying the most critical components that lead to the largest irreversibility and identifying the thermodynamic potential for enhanced cogeneration plants. As a result, oxyfuel equipped platforms provide a diversified set of advantages, while keeping competitive efficiencies. For instance, advanced systems allow for cutting down ostensibly the atmospheric CO2 emissions compared to the conventional and amine-based power plant configurations of the FPSO.

Modeling of chemical processes using commercial and open-source software: A comparison between Aspen Plus and DWSIM

Computer simulation plays a key role in chemical process design. Currently, there are a large number of widely accepted commercial software. For example, Aspen Plus which was used to simulate offshore petroleum production processes, but it is often too costly to purchase and maintain a valid software license. On the other hand, since open-source software is freely accessible, the simulation models developed using open-source software could be studied, reviewed, and modified by any interested parties. This would help promoting technology transfer and knowledge dissemination in both academic and industry sectors. We specifically focus on the simulation of chemical process using the modeling software to evaluate thermal and chemical behaviour of the system which uses the chemical processes related to offshore petroleum production facilities as an example to demonstrate the software capabilities of both Aspen Plus and DWSIM. This work emphasizes on the comparison of simulation results calculated by commercial software namely Aspen Plus vs. open-source software called DWSIM (An open-source sequential modular steady state simulator) [1]. The simulation was carried out under the steady-state conditions, adiabatic processes, and negligible pressure losses. Finally, simulation results from DWSIM and Aspen Plus were compared with the heat and mass flow diagram which was used as reference. It was found that the discrepancy between simulation and reported values was in general less than 5%. It has been demonstrated that free and open-source software like DWSIM could potentially perform similar tasks as commercial software.

Hydrate-Induced Vibration in an Offshore Pipeline

Summary Gas-hydrate plugging poses an operational challenge to offshore petroleum production and transportation. In this study, a computational-fluid-dynamics (CFD) model that uses ANSYS Fluent (ANSYS 2019) multiphase-flow-modeling techniques to simulate and analyze the effect of gas-hydrate flow in pipelines is proposed. For this purpose, the study attempted to integrate the ANSYS Fluent model with an existing commercial subsea-pipeline-visualization tool. To validate the simulation results, two case studies were conducted. The first study was about a pipeline whose dimensions are based on the specifications in existing literature (Balakin et al. 2010a). The second study was about a pipeline with more-complex geometry (M-shaped jumper with six elbows). The Eulerian/Eulerian method was used to model the multiphase hydrate flow. The population-balance method (PBM) was then used to model hydrate agglomeration and its breakup mechanism in the flow. A parametric study of the stresses in the pipelines resulting from flow-induced vibration (FIV) was conducted to identify the regions that underwent the maximum stresses and deformations under various flow conditions. The tool can be used in the petroleum industry to identify the operational hazards in offshore structures and to take necessary safety measures to avoid any potential catastrophic events.

Ultra-deepwater seismic plays offshore Brazil — Future drilling off Santos and Campos Basins

Contemporaneous seismic data acquisition in the Santos and Campos Basins offshore Brazil have focused on image characterization of deepwater and ultra-deepwater reservoirs and their relationship with hydrocarbons originating from synrift source rocks. Our interpretation has mapped the stratigraphy of postsalt turbidite reservoirs, and, on the presalt lithology, it has uncovered the underlying synrift sequences that embrace oil-bearing source rocks and the prolific, recently discovered, microbialite carbonate reservoirs. The new phase in geophysical data acquisition and offshore drilling that started in 1999 bolstered the Brazilian offshore petroleum production to record levels. The new, massive, nonexclusive, speculative 2D and 3D data acquisition surveys conducted offshore the Brazilian coast far exceed the amount of all existing cumulative vintage data. Deepwater drilling programs probed the interpreted new prospects. As whole, the modern geophysics data libraries offshore Brazil brought in the technology era to seismic interpretation, reservoir characterization, and geosteering operations in deepwater development drilling. Still, regional interpretation mapping of the outer shelf, slope, deepwater and ultra-deepwater provinces of the Santos and Campos Basins indicates plenty of prospective future drilling in the salt locked minibasins of the ultra-deepwater provinces. Salt tectonics shapes the architecture of these basins; hence, postsalt deepwater turbidite plays were readily interpreted from seismic amplitudes of the modern data that also allow for resolution images of the synrift source rocks, salt architecture, migration paths through faulting and salt windows, reservoir characterization, and regional seal mapping. The new techniques of prestack depth migration have enabled uncovering the imaging structure of the synrift that led to characterization of the presalt carbonate reservoirs and discovery of giant accumulations. Future offshore exploration will continue aiming at postsalt deepwater and ultra-deepwater minibasins plus presalt plays under the massive salt walls, still an underexplored frontier.

Exergy assessment and energy integration of advanced gas turbine cycles on an offshore petroleum production platform

On offshore platform applications, power and heat are normally supplied by simple open cycle gas turbine (OCGT) and heat recovery steam generators (HRSG) at lower efficiencies if compared to onshore combined cycle systems. Certainly, due to the reduced available space and the weight constraints, combined cycles are not commonly considered as cogeneration systems on conventional offshore petroleum platforms. However, more stringent environmental policies for the natural gas and oil production activities have motivated the integration assessment of advanced technological solutions that aim to mitigate the environmental impact that conventional offshore platforms are responsible for. Accordingly, in this paper, the effect of the integration of a low emission, oxyfuel gas turbine cycle is analyzed and compared against an amines-based post-combustion system and a conventional offshore petroleum platform operation in terms of its exergy efficiency and reduced atmospheric CO2 emissions. Indeed, although the conventional configuration is the most efficient, the oxyfuel powered platform configuration presents close power cycle efficiency of 27.10% and the lowest specific CO2 emissions of 0.014 kgCO2/toil, whereas the amines-based layout provides the best cogeneration efficiency (55.34%) of the advanced configurations. Moreover, an energy integration analysis is performed to identify the heat recovery potential, while the exergy method is used to evaluate and quantify the most critical components that lead to the largest irreversibilities along the primary separation, cogeneration and gas compression systems. As a result, the study points to ways of decarbonizing offshore applications in the oil and gas sector.

Changes in the Microbial Community Diversity of Oil Exploitation.

To systematically evaluate the ecological changes of an active offshore petroleum production system, the variation of microbial communities at several sites (virgin field, wellhead, storage tank) of an oil production facility in east China was investigated by sequencing the V3 to V4 regions of 16S ribosomal ribonucleic acid (rRNA) of microorganisms. In general, a decrease of microbial community richness and diversity in petroleum mining was observed, as measured by operational taxonomic unit (OTU) numbers, α (Chao1 and Shannon indices), and β (principal coordinate analysis) diversity. Microbial community structure was strongly affected by environmental factors at the phylum and genus levels. At the phylum level, virgin field and wellhead were dominated by Proteobacteria, while the storage tank had higher presence of Firmicutes (29.3–66.9%). Specifically, the wellhead displayed a lower presentence of Proteobacteria (48.6–53.4.0%) and a higher presence of Firmicutes (24.4–29.6%) than the virgin field. At the genus level, the predominant genera were Ochrobactrum and Acinetobacter in the virgin field, Lactococcus and Pseudomonas in the wellhead, and Prauseria and Bacillus in the storage tank. Our study revealed that the microbial community structure was strongly affected by the surrounding environmental factors, such as temperature, oxygen content, salinity, and pH, which could be altered because of the oil production. It was observed that the various microbiomes produced surfactants, transforming the biohazard and degrading hydro-carbon. Altering the microbiome growth condition by appropriate human intervention and taking advantage of natural microbial resources can further enhance oil recovery technology.

Multi-project environmental impact assessment: insights from offshore oil and gas development in Brazil

ABSTRACTDespite being adopted worldwide, environmental impact assessment (EIA) is under pressure in many countries, while perceived (rightly or wrongly) as an ineffective and inefficient process. Strategic environmental assessment (SEA) is thought to help address some of EIA’s shortcomings, but it is absent in many jurisdictions and sectors. In this paper, we argue that multi-project EIA can, in some contexts, simultaneously deliver greater effectiveness and process streamlining. To illustrate our claim, we present a case study from offshore petroleum production in Brazil, where the development of the pre-salt giant reserves is being licensed through a multi-project EIA approach, in a non-SEA planning environment. The analysis provides interesting insights on the strengths and challenges of that strategy, focusing on five aspects of practice: cumulative impacts, efficiency, approach to authorizations, follow-up and political issues. Proper scoping was found to be essential to consistent EIA processes and shorter review times. Finally, we suggest that multi-project EIA approach should be revisited by practitioners and regulators to identify opportunities for deployment, especially in jurisdictions where strategic assessments are not in place.

Unit exergy cost and CO2 emissions of offshore petroleum production

The assessment of the exergy spent for production of oil and gas on offshore platforms is of primordial importance for evaluation of the environmental impact associated with petroleum derived substances. In this work the exergy cost for oil and gas produced on a Floating Production Storage and Offload (FPSO) ship is evaluated along the lifespan of the well taking off-design operation conditions of process plant and cogeneration plant into account. The impact of 3 different cogeneration plants and 2 different process plant operating modes was assessed. Distribution of exergy costs for the oil and gas was obtained using thermoeconomy to reduce the arbitrariness of cost partition criteria. Results reveal that the exergy cost of oil varies from 1.0 kJ/kJ to 3.2 kJ/kJ along the well lifespan depending on process plant operating mode and cogeneration plant configuration. The exergy cost of gas varies from 1.0 kJ/kJ to 2.4 kJ/kJ along the well lifespan depending on cogeneration plant configuration. The average emission of CO2 for the natural gas ranges from 19.0 gCO2/MJ to 19.8 gCO2/MJ depending on the cogeneration plant configuration while for the oil it ranges from 19.4 gCO2/MJ to 26.8 gCO2/MJ and it also depends on process plant operating mode.