Petroleum Production Facilities Research Articles

Advancing Water Deoiling Efficiency in Petroleum Production: A Comprehensive Case Study of Hybrid Flotation Technology Integration

_ The efficient management of increasing water cuts in oil fields is paramount for sustaining profitability and minimizing environmental impact. This article presents a comprehensive case study conducted by Saudi Aramco, focusing on the integration of hybrid flotation technology into a gravity water/oil separator (WOSEP) to enhance deoiling efficiency and reduce operational costs and carbon emissions. The retrofit involved merging enhanced gravity separation with induced gas flotation (IGF) within the same vessel, resulting in significant improvements in deoiling capacity, outlet oil-in-water content reduction, and operational efficiency. Detailed insights into the design, operation, and performance of hybrid flotation systems are provided, offering valuable guidance for similar initiatives in the petroleum industry. Introduction Petroleum production facilities face escalating challenges with increasing water-production rates during crude-oil extraction, particularly in waterflooding operations for secondary oil recovery. This trend not only escalates operational costs but also intensifies environmental concerns, particularly regarding energy consumption and carbon emissions associated with water-handling processes. In response to these challenges, Saudi Aramco embarked on a pioneering initiative to enhance water-deoiling efficiency by integrating hybrid flotation technology into a conventional gravity WOSEP. This case study presents a comprehensive analysis of the design, implementation, and outcomes of this transformative project, offering valuable insights for the broader petroleum industry. Methodology The upgrade process commenced with an assessment of the existing WOSEP system and its operational challenges. Recognizing the impending capacity constraints and escalating oil-in-water content, Saudi Aramco’s engineering team opted for a holistic approach that combined enhanced gravity separation with IGF within the same vessel. The retrofit involved reconfiguring the internal components of the WOSEP to accommodate the hybrid flotation system, including the installation of advanced plate-pack internals for gravity separation and the integration of IGF cells for additional oil removal. Rigorous testing and optimization procedures were conducted to ensure seamless integration and optimal performance of the hybrid system. Gas/Oil Separation Plant Process Description In a typical gas/oil separation plant, the initial phase involves the extraction of crude oil, associated gas, and produced water from wells via a production manifold. These constituents are then directed to a three-phase separator, also known as a high-pressure production trap (HPPT). In the HPPT, free water droplets are separated from the oil through gravity separation, aided by demulsifier injection at the production header. The separated free water is discharged to a WOSEP, typically a gravity separator, for deoiling.

Asphaltene Adsorption on Solid Surfaces Investigated Using Quartz Crystal Microbalance with Dissipation under Flow Conditions.

Asphaltenes can cause operational challenges in petroleum production facilities and adversely affect production by adsorption on mineral surfaces and alteration of the oil wettability of reservoirs. Therefore, understanding asphaltene adsorption mechanisms and their effects is crucial to improving the efficiency of oil production and reducing costs. In this study, we focus on understanding the impact of asphaltene concentration and the depositing environment of asphaltene adsorption on solid surfaces using the quartz crystal microbalance with dissipation (QCM-D) technique. The initial and long-term kinetics of adsorption at different concentrations were examined on three different solid surfaces including silicon dioxide to represent quartz mineral, stainless steel, and gold. The frequency-dissipation data showed evidence of monolayer adsorption initially, followed by multilayer formation. At short times, the adsorbed mass increased linearly with time, suggesting that the process was kinetically controlled rather than diffusion-controlled. The results were reproducible and did not depend on convection velocity but did depend on the surface material. At later stages, the monolayer development appeared to follow the random sequential adsorption (RSA) theory. Once multilayer adsorption commenced, the rates agreed well with the two-layer model of Zhu and Gu, 1990. The impact of asphaltene adsorption on the wettability of the surface was examined using contact angle studies, which showed decreasing water wettability with an increase in the adsorbed mass. The contact angle of water after 12 h of adsorption leveled off at around 100° on all three surfaces. Contact angle measurements were also used to evaluate if brine salinity causes the wettability alteration of surfaces with the adsorbed asphaltene. The results indicate that at 3% NaCl solution, the contact angle decreased only slightly by less than 2°.

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].

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.

Geoenvironmental assessment of the effect of oil extraction on the landscapes of the Chechen Republic

This paper analyzes the situation connected with the effect of oil extraction on the landscapes of the Chechen Republic. This study shows that the association of the Republic’s petroleum production facilities with its mountainous regions with complex geological, geomorphological, and tectonic structures and the transitional areas conditioned the high inhomogeneity of the development of landscapes. The consequence of such development is the current complicated environmental situation both within the boundaries of the Republic’s particular districts (depending on the location of oil extraction facilities) and within the territory of the Republic’s capital itself as an urbanized landscape.

What to Do After the Storm: Maintenance and Restoration Planning for Natural Disaster Recovery

Petroleum and chemical production facilities are often concentrated along coastal regions, where they are especially vulnerable to hurricanes or typhoons. Electric motors, switchgear, and related equipment are sensitive to damage from flooding, and replacements often have long lead times. This article offers practical methods for restoring electrical equipment as well as guidance for repair-replace decisions with a focus on getting the plant back in operation as soon as possible. It also offers advice about expected life reduction for electrical equipment that is not properly handled after such an event. Since similar production facilities are regionally concentrated, multiple facilities impacted by the same disaster will be competing for limited repair and replacement resources. Having a proactive recovery plan before a storm can significantly reduce the time required to restore production. Understanding the long-term effects of saltwater on electric motors and generators is vital to capital expense forecasting for the years following a major storm.

Investigation of asphaltene deposition under dynamic flow conditions

Asphaltene deposition is one of the most serious problems, which usually occurs in oil wells, petroleum production, oil processing, and transportation facilities. Deposition of heavy organic components, especially asphaltene, can lead to wellbore blockage and impacts well economics due to reduction in oil production. Therefore, it is necessary to pay more attention to finding some solution to overcome this problem. In this study, a pipe-loop apparatus for investigation of oil stability was employed to measure deposition thickness using a thermal method. The effects of many factors such as oil type, oil temperature, oil velocity, inhibitors, and solvents on asphaltene deposition were investigated. The results showed that the deposition increased with the increasing value of the colloidal instability index. Besides, the deposition thickness increased with the decreasing velocity of oil, but did not change with oil temperature. In addition, n-heptane could result in more deposition; however, toluene had no effect on the deposition. Branched dodecyl benzene sulfonic acid (Branched DBSA) and Linear DBSA as inhibitors decreased the rate of asphaltene deposition.

System reliability as perceived by maintenance personnel on petroleum production facilities

The aim of this research was to understand the relationship between maintenance staff perceptions of organisational effectiveness and operational reliability in petroleum operations. Engineering measures exist that assess the effectiveness of maintenance and reliability of equipment. These measures are typically retrospective and may not provide insight into what impedes system reliability. Perceptions of organisational effectiveness by the workforce may provide a predictive measure that could improve our understanding of the human factors that influence system reliability.Maintenance personnel (n=133) from nine petroleum production facilities completed a survey as part of a study of human factors and maintenance reliability. 69 respondents (51.9%) provided comments to an open-ended question in the survey, and these data were analysed using Interpretive Phenomenological Analysis to extract themes. Four super-ordinate themes were identified from the analysis: 1) Communication and access to information, 2) Efficiency of current work systems, 3) Need for better workgroup support, and 4) Management impacts on the workplace. We found a significant relationship between the frequency of the four super-ordinate themes and the facility reliability level as measured by ‘Mean Time Between Failures’: χ2(6,N=158)=16.2, p=.013. These results demonstrated that operational effectiveness might be differentiated on the basis of survey-derived perceptions of maintenance personnel.

Modeling of hydrogen sulfide removal from Petroleum production facilities using H2S scavenger

The scavenging of hydrogen sulfide is the preferred method for minimizing the corrosion and operational risks in oil production facilities. Hydrogen sulfide removal from multiphase produced fluids prior to phase separation and processing by injection of EPRI H2S scavenger solution (one of the chemical products of Egyptian Petroleum Research Institute) into the gas phase by using the considered chemical system corresponds to an existing oil well in Qarun Petroleum Company was modeled. Using a kinetic model the value of H2S in the three phases was determined along the flow path from well to separator tanks. The effect of variable parameters such as, gas flow rates, chemical injection doses, pipe diameter and length on mass transfer coefficient KGa, H2S outlet concentration and H2S scavenger efficiency has been studied. The modeling of the hydrogen sulfide concentration profiles for different conditions was performed. The results may be helpful in estimating injection rates of H2S scavengers for similar fields and conditions.

Experimental characterization of vertical downward two-phase annular flows using Wire-Mesh Sensor

Annular two-phase flow has been vastly investigated because of its large and deep involvement in industrial processes, particularly in nuclear engineering and petroleum production facilities. Much effort has been devoted to investigating upward flows involving the flow patterns, void fraction, as well as local interfacial characteristics. However, research for vertical downward two-phase flow, especially of the interfacial characteristics, are comparatively scarce. In order to gain insight on void fraction, interfacial structures and characteristics frequencies, experimental work was performed in downward annular two-phase flow with water and air as process fluids at low pressure conditions. A flow loop, including a 76mm ID, 16.5m long vertical pipe, has been instrumented. A state-of-the-art instrument for two-phase flow measurements based on the fluid conductivity, namely dual Wire-Mesh Sensor (WMS) has been utilized to acquire the experimental data. A total of 43 data points have been acquired at superficial liquid velocities that ranged from 0.005m/s to 0.10m/s and superficial gas velocities that varied from 10m/s to 31m/s. The effects of liquid viscosity on the measured parameters are also investigated using two different viscosities of 1 and 10cP. Analysis of time series void fraction data from the dual Wire-Mesh Sensors allows the determination of cross-sectional averaged void fraction, local time averaged void fraction distribution, liquid phase distribution around the tube periphery, interfacial structure frequencies, pseudo 3D reconstruction as well as Probability Density Function (PDF) and Power Spectral Density (PSD). The experimental results indicate that the interfacial shape and frequencies are significantly altered by the superficial gas velocity. Comparisons between mechanistic model predictions and the acquired experimental data show a maximum absolute average relative error of approximately 7% for the cross-section void fraction.

Under-Deposit Caustic Corrosion on Sodium Carbonate Pipeline

Under deposit corrosion (UDC) is defined as a localized corrosion that develop beneath or around deposit on a metal surface. UDC represents an important threat in the integrity matrix of petroleum and petrochemical production and transportation facilities, and has been cited as responsible for high corrosion rates and loss of containment during operations. For a sodium carbonate production process, crude caustic from the caustic plant enters the sodium carbonate storage tanks. When the batch cycle begins, crude caustic is pumped to the top of the carbonation tower. The caustic stream flows down through two packed sections where it contacts boiler's stack flue gas rising up through the tower. The caustic (sodium hydroxide) reacts with the carbon dioxide in the flue gas to form sodium carbonate. A carbon steel pipeline then transports sodium carbonate. This carbon steel pipeline experiences frequent leaks. An investigation was conducted to identify the types and possible causes of the corrosion on the sodium carbonate pipeline. XRF (X-Ray Fluorescence Spectrometry) and carbon/sulfur analyzer and XRD were used to chemically identify the deposited materials in the pipeline and to study the damage morphology. It was concluded the failure of the pipeline is attributed to caustic corrosion aggravated by deposited of process carry-over materials.

Subsea Electrical Submersible Pump Significance in Petroleum Offshore Production

The use of pumping methods in offshore applications has become common especially in viscous oil production. This follow from the fact they present better efficiency and higher production rate than other lift methods when used in the same conditions, for instance gas lift. Thus, a lift method that has been often used on this scenario due to its satisfactory results is the subsea electrical submersible pump (subsea ESP). This article presents the modeling and simulations of petroleum production facilities equipped with subsea ESP using a commercial software package, the pipesim® from Schlumberger. The production facilities consist of a single vertical producing well completed through its whole thickness in an offshore reservoir. It has been proposed two configurations differing only on the location of the equipment. In the first case, the subsea ESP was installed inside the wellbore and, in the second case on the seabed downstream the wet X-tree. The production rate was simulated for both cases, allowing comparison of the results of each configuration.

Mapping factors influencing the selection of subsea petroleum production systems: a case study

The development, design, and selection of subsea petroleum production equipment and facilities are critical activities, as the decisions made will impact the success and profitability of the project. Pre-studies need to be conducted to design the best subsea concept and to assess the development costs in order to succeed in the project execution and to keep the production rate and profits as expected. Technical, economic, and government regulations are some of the factors that need to be evaluated in order to contract subsea services and procurement activities. However, there are many other factors that should be addressed before selecting the concept. By identifying and studying these aspects, one will be able to develop and select the best equipment to cover the functions needed, as well as to identify health, safety, environmental and quality requirements and spare parts’ availability for maintenance interventions. Based on a literature study and an industrial case study, in this paper we identify, map, validate and systematically rank various aspects, factors, and design criteria that need to be addressed in the design and selection of subsea oil and gas production systems.

Assessment of greenhouse gas mitigation options and costs for California Petroleum Industry facilities: The shape of things to come

The California Global Warming Solutions Act of 2006 sets a goal for the state to reduce its greenhouse gas emissions to 1990 levels by 2020. In preparation for implementation of a cap and trade program under this Act, Chevron has undertaken a detailed assessment of greenhouse gas mitigation options and costs. Such an assessment is key to making compliance decisions within the constraints of a given cap and trade regime. If the cap and trade market is minimally restricted (i.e., recognizes that climate change is a global issue and thus has no geographic restrictions and no set requirement for onsite emission reductions), facilities can make the best economic (and environmental) choices of where to ‘make’ emission reductions inside the facility fenceline and when to ‘buy’ the emission reduction allowances or credits on the market. The scope of the study included Chevron’s two refineries and a large heavy oil steamflood production operation in California. This paper will discuss how mitigation technologies are identified and assessed, describe some of the key greenhouse gas mitigation alternatives of interest to the Chevron California facilities and present a business-based approach to analyzing mitigation costs. Technologies studied included energy efficiency, advanced energy (solar, wind, geothermal, biomass, nuclear, low temperature heat recovery) and carbon dioxide capture and storage (CCS). For each mitigation option, a consistent methodology, based on the International Petroleum Industry Environmental Conservation Association/American Petroleum Institute (IPIECA/API) Guidelines for Evaluation of Greenhouse Gas Emission Reduction Projects was used to assess baseline or ‘business as usual’ emissions, net emission reductions due to the project, capital cost, operating cost and any project benefits (e.g., reduced fuel use for energy efficiency projects). These values were then entered into a business evaluation tool to calculate a Net Present Value for each option. Key conclusions: Broad involvement of various disciplines is needed to identify new alternatives for greenhouse gas mitigation technologies. Other than CCS, options for significant reductions of refinery and petroleum production emissions were extremely limited in the facilities studied. Since cost-effective, feasible options are limited for refineries and petroleum production facilities, availability of sufficient allowances and offsets is an important element if state goals are to be achieved. Although a number of energy efficiency projects were identified, the cumulative total emissions reductions available through energy efficiency projects is minimal. Renewable and advanced energy projects that generate electricity generally have very high mitigation costs, and may not greatly benefit facilities if emission caps apply only to direct emissions, since these projects reduce the quantity of purchased electricity rather than emissions from the facility itself (and are therefore not eligible for credit under most regulatory design schemes). Renewable and advanced energy technologies for steam generation may have significant mitigation potential for heavy oil steamflood production. Further development and demonstration is needed to determine whether these technologies will be viable. In order to support good business decisions, it is important that greenhouse gas mitigation technology evaluation be done in a manner consistent with other business evaluation processes.

Air quality index pattern around petroleum production facilities

PurposeThe aim of this paper is to better understand the impact of petroleum production facilities on ambient air quality of host airshed.Design/methodology/approachField measurements were taken daily for four consecutive months around petroleum production facilities in the Niger Delta area, of Nigeria, one of the world's important petroleum producing areas. Statistical analysis tool and air quality analytical tool known as the air quality index (AQI) were applied on the field data obtained.FindingsThe mean measured daily concentrations of both carbon monoxide (CO) and nitrogen dioxide (NO2) between distances 50 and 500 m of petroleum flow stations were of the range 140 – 3400 μg/m3 and 23 – 1250 μg/m3 respectively. The AQI from measured CO concentrations in the study area ranged between 1 and 44, an indication of good AQI category with no known health effects but a need for cautionary statement. Similarly, over 97 percent of the measured concentrations of NO2 were below 0.60 ppm which implies that the AQI of the host environment of the flow stations were below 200 with respect to NO2 thus indicating a good category of air with no health alarm. However, at the 60 m distance around a flow station, the AQI was 210 thus the quality of available air at this point could be described as very unhealthy. Generally the concentrations of CO were higher than NO2 in all the distances from the flow stations and were corroborated with their significant T‐test values. The T‐test results of the relationship between the concentrations of the air pollutants per time of the day, showed that their T‐test values were not significant, indicating that concentrations of these air pollutants were independent of the sampling time. A strong and positive correlation existed between the two air pollutants signifying common sources.Originality/valueThe paper highlights that at 60 m distance around petroleum production facilities, people with respiratory or heart disease, the elderly and children should be prevented from gaining access in the morning without taking necessary precautionary measures against the inhalation of air pollutants.

An approach for prediction of petroleum production facility performance considering Arctic influence factors

As the oil and gas (O&G) industry is increasing the focus on petroleum exploration and development in the Arctic region, it is becoming increasingly important to design exploration and production facilities to suit the local operating conditions. The cold and harsh climate, the long distance from customer and suppliers’ markets, and the sensitive environment may have considerable influence on the choice of design solutions and production performance characteristics such as throughput capacity, reliability, availability, maintainability, and supportability (RAMS) as well as operational and maintenance activities. Due to this, data and information collected for similar systems used in a normal climate may not be suitable. Hence, it is important to study and develop methods for prediction of the production performance characteristics during the design and operation phases. The aim of this paper is to present an approach for prediction of the production performance for oil and gas production facilities considering influencing factors in Arctic conditions. The proportional repair model (PRM) is developed in order to predict repair rate in Arctic conditions. The model is based on the proportional hazard model (PHM). A simple case study is used to demonstrate how the proposed approach can be applied.

Effects of sheens associated with offshore oil and gas development on the feather microstructure of pelagic seabirds

Operational discharges of hydrocarbons from maritime activities can have major cumulative impacts on marine ecosystems. Small quantities of oil (i.e., 10ml) results in often lethally reduced thermoregulation in seabirds. Thin sheens of oil and drilling fluids form around offshore petroleum production structures from currently permissible operational discharges of hydrocarbons. Methodology was developed to measure feather microstructure impacts (amalgamation index or AI) associated with sheen exposure. We collected feather samples from two common North Atlantic species of seabirds; Common Murres (Uria aalge) and Dovekies (Alle alle). Impacts were compared after feather exposure to crude oil and synthetic lubricant sheens of varying thicknesses. Feather weight and microstructure changed significantly for both species after exposure to thin sheens of crude oil and synthetic drilling fluids. Thus, seabirds may be impacted by thin sheens forming around offshore petroleum production facilities from discharged produced water containing currently admissible concentrations of hydrocarbons.

Equivalent Carbon Dioxide Capture and Storage Processes in Offshore Petroleum Production Facilities

The present study approaches the economic and technical evaluation of equivalent carbon dioxide (CO2 eqv.) capture and storage processes, considered in a proposal case compared to a base case. The base case considers an offshore petroleum production facility, with high CO2 content (4 vol%) in the composition of the produced gas and both CO2 and natural gas emissions to the atmosphere, called CO2 eqv. emissions. The results obtained with this study, by using a Hysys process simulator, showed a CO2 emission reduction of 65% comparing the proposal case in relation to the base case.

INTEGRITY OF BOLTED JOINTS: HYDROCARBON LEAK REDUCTION BY JOINT-INTEGRITY MANAGEMENT

Bolted joints are very common in petroleum production facilities. Whereas extensive controls are applied to the production of a welded joint—in terms of material control and specification, control and competence of the welder, and verification of the integrity of the weld—this is not the case for bolted joints. The consequences of failure of a welded joint and a bolted joint, however, are similar and potentially catastrophic if the contents of the pipeline or vessel are hydrocarbons under pressure. This paper discusses the main issues in producing and maintaining a leak-free bolted joint and makes the case for establishing industry-wide standards for the management of bolted joints that are equally as stringent as those applied to welded joints.Implementing such a system, whilst improving and assuring the safety and environmental performance of an asset, will also reduce costs due to rework, product loss, schedule slippage and production downtime.

Overview: Production/Facilities (December 2005)

This year’s selection of papers is a mixed bunch that I thought would appeal to a wide audience. I deliberately chose papers to encourage as many as possible to read them. The broad theme is environment and sustainability. We have a duty to limit gas flaring as much as practicable to limit emissions and conserve fuel. A little-known effect of excessive flaring is addressed in the first paper. It’s a common saying that oil and water don’t mix. Well, the truth is that sometimes they do. The food-processing industry spends a lot of time mixing oils and water that they sell us as food. However, in this industry, our problem is often finding ways to separate oil and water. No two sets of oil and water are the same, and the second paper looks at experiences in a Saudi Arabian field. As our supply of high-quality light sweet crude oil is depleted, we start to produce the heavier sour grades of crude oil around the world. One of the problems with these fields is disposal of the large quantities of elemental sulfur that are recovered during the processing. Until now, it has often been stockpiled with, in my view, huge safety and environmental risks. Our third paper presents some novel means to dispose of this sulfur. Our final paper deals with the end time for a production facility. Whether onshore or offshore, the production and processing facilities must be removed in accordance with local regulations. This task is clearly more difficult offshore, and this paper explains how it was handled offshore California. I hope that you enjoy reading them as much as I enjoyed choosing them. Available from the SPE eLibrary: www.spe.org SPE 93653 “ExxonMobil’s Advanced Gas-to-Liquids Technology—AGC-21,” by R.A. Fiato, ExxonMobil Research and Engineering Co., et al. SPE 93817 “Restoring Integrity to Aged Petroleum Production Facilities,” by S.W. Ciaraldi, BP Indonesia, et al. SPE 96403 “Turning a North Sea Oil Giant Into a Gas Field—Depressurization of the Statfjord Field,” by R. Boge, SPE, Statoil, et al. SPE 96504 “Canopy Bridges Along a Rainforest Pipeline in Ecuador,” by M. Thurber, SPE, Walsh, et al.