Gas Oil Separation Plant Research Articles

Maximization of Gas-Oil Separation Plant Oil Recovery by Operation Parameter Optimization

Summary Maximizing oil recovery of the gas-oil separation plant (GOSP) is intended to increase revenue in the oil and gas industry. The GOSP is an integral part of the petroleum industry, and it consists of multistage separators, a heater-treater, desalination, a stabilization column, and a stock tank of oil. It is conventional practice to operate the GOSP at fixed operating conditions without considering the effects of variation for different parameters such as ambient temperature, chemical composition, reboiler (60°C, 65°C, and 70°C), and stabilization (temperature and pressure). Optimizing the GOSP parameters can help to maximize the GOSP oil recovery and, as a result, increase the revenue and profit. This study aims to optimize operation parameters to maximize the oil recovery of the GOSP at which the maximum oil recovery can be obtained from the GOSP. To achieve the objective of this study, first, a GOSP model was built using Petro-SIM process simulator software for a typical Saudi Aramco GOSP. The input data for the process simulator were the data from the initial pressure/volume/temperature (PVT) analysis. Optimizer tools in Petro-SIM were used to estimate the optimal conditions of the GOSP for achieving maximum oil recovery. The results showed that the optimization of the GOSP parameters such as ambient temperature, high-pressure separator (HPS), low-pressure separator (LPS), reboiler temperature, and stabilization pressure and temperature have a significant effect on the GOSP oil recovery and lead to increased revenues. Adjusting the HPS and LPS pressures to the optimal values at each ambient temperature significantly improves the GOSP oil recovery and can generate extra revenue of more than USD 500 million for 3 months considering the typical climate condition and GOSP (50,000 B/D capacity) in Saudi Arabia.

Saudi Arabia Case Study Illustrates Road to Zero Routine Gas Flaring

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21182, “The Road to Zero Routine Gas Flaring: A Case Study From Saudi Arabia,” by Majed Alsuwailem, KAPSARC. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ The complete paper discusses Saudi Arabia’s progress in gas flaring, the measures the government has taken, and how operators have adapted. It also identifies many lessons learned and technological solutions that could be scaled up on a national or a corporate level to reduce gas flaring to achieve zero routine flaring targets, especially in cases where the state owns hydrocarbon assets and leases them to private operators. History of Gas Flaring in Saudi Arabia Following the discovery in 1948 of Ghawar, Saudi Arabia’s largest oil field, oil production in the country increased and more associated gas was produced and flared. The national oil company, Saudi Aramco, had no interest in capturing gas produced from its oil operations. No local or regional market for it existed, and exporting the gas would have required substantial infrastructure investments. This coincided with periods of low crude oil prices that made gas projects uneconomical. However, as the 1960s and ’70s passed, gas came to be increasingly regarded as an essential part of a broader attempt to diversify the Saudi economy. This, in return, allowed the creation of jobs in new frontiers, including the refining and petrochemical industries. In the early 1970s, the Saudi Ministry of Petroleum and Minerals contracted the Texas Eastern Corporation to conduct a technical and economic feasibility study. It evaluated the benefits of establishing a massive refining and petrochemical industry in the city of Jubail on the Arabian Gulf and Yanbu on the Red Sea, with gas as an important feedstock. The study required major capital expenditures on midstream oil operations. Saudi Aramco, on the other hand, proposed exploiting associated gas to generate electricity. Because the price of oil did not exceed $3/bbl before the 1970s, the Saudi government opted for the first option. Saudi Aramco, however, only foresaw an opportunity in this development if the government contributed major capital to the midstream, resulting in a positive outcome for both the stakeholders and the operator, which turned out to be the case. Master Gas System (MGS) The government gave Saudi Aramco a contract to establish the $12 billion MGS to capture, process, and use gas as fuel and feedstock for the petrochemical plants. Most of this project was paid for by the government. By the fall of 1982, the key components of the MGS (gas-gathering and -processing facilities and pipelines) were fully operational. The MGS saved 4.2 billion scf of gas from being flared, which prevented 80 million tonnes of carbon dioxide from being emitted into the atmosphere annually. Over time, the MGS has been expanded as more oil and nonassociated gas fields have been placed onstream and as demand has risen for dry gas in the power sector. By 2018, the MGS had gathered almost 3.5 trillion ft3/yr and is one of the world’s largest single hydrocarbon networks. It includes 4,000 km of pipelines, 50 gas/oil separation plants (GOSPs), seven gas plants, and two natural gas/liquid units.

Intelligent Approach for Gas-Oil Separation Plant Oil Recovery Enhancement

Summary The present practice is to operate the gas-oil separation plant (GOSP) at the predetermined set of conditions obtained during the design stage. These predetermined sets of conditions are fixed and do not account for the effects due to changes in the ambient temperature (Ta), resulting in low recovery and profitability. The variation of Ta highly affects the separation process, where Ta varies greatly from summer to winter. Thus, this study proposes an intelligent approach to maximize profitability by improving the oil recovery through optimization of low-pressure production trap (LPPT) and high-pressure production trap (HPPT) accounting for the changes in the Ta. This work also proposes an advisory system for guiding the operation team to set the HPPT/LPPT pressure at an optimal value that accounts for the changes in Ta for maximizing the oil recovery. To generate the data accounting for the variation in Ta, a GOSP model was developed using the OmegaLand dynamic simulator. A typical Saudi Aramco GOSP parameter was used for the design. The oil recovery was obtained for the various runs of simulation for the representative range of HPPT/LPPT pressure over a wide range of Ta. Then, artificial intelligence (AI) techniques were applied to determine the optimal pressure of LPPT and HPPT units, and an intelligent advisory system is developed based on the correlation obtained for the optimal set of pressure according to the variation in Ta. Results show that at constant HPPT and LPPT pressure, liquid recovery decreases with an increase in Ta, suggesting that readjustment in HPPT or LPPT operating pressure can counter the temperature changes to improve the oil recovery. The analysis of the results reveals that at a fixed value of Ta and LPPT pressure, the oil recovery increases with an increase in HPPT pressure up to the optimal value of HPPT pressure and then decreases above the value of optimal HPPT pressure. Similarly, when the HPPT pressure and Ta are fixed, the oil recovery increases with an increase in LPPT pressure until it reaches the optimal value and then decreases above the value of optimal LPPT pressure. The improvement in the oil recovery signifies the existence of optimal pressure conditions for HPPT/LPPT separators at which maximum oil recovery can be obtained. This study shows the novel way to incorporate the changes in the ambient condition by optimizing LPPT/HPPT operating pressure for enhancing the liquid recovery of the GOSP plant. The advisory system developed from this study maximizes the oil recovery by determining the optimal set of operating conditions for the HPPT/LPPT separators.

Better Heat and Power Integration of an Existing Gas-Oil Plant in Egypt Through Revamping the Design and Organic Rankine Cycle

Objective: The current study aims mainly to Maximize Condensate Recovery (NGLs), focusing on a gas processing train of Gas-Oil Separation Plant (GOSP) located in Egypt with a capacity of 4,230 kmole/h. Methods: The research study accounts for the constraint of Reid Vapor Pressure (RVP) specification, which makes the storage in floating roof tanks is of a great risk. The study proposes the installation of the cryogenic train that recovers condensates (C4+). This train comprises of compression unit, expansion unit, three-phase separators and a re-boiled absorber. The problem of RVP will no longer exist because of the re-boiled absorber achieving RVP according to export specifications (RVP below 82.74 kPa). Heat integration is applied over the whole process to minimize the reliability of the external utilities. Further, an Organic Rankine cycle (ORC) is introduced to the existing unit for more heat integration to develop useful work from process waste heat. Furthermore, both environmental emissions of CO2 and economic implications are investigated. Results: Energy integration played a vital role in decreasing the compressing power by about 31%, the cooling load by about 81%, and eliminating the heating load leading to zero CO2 emissions. Conclusion: The new energy-integrated retrofit scenarios exceed the recommended revamping schemes by previous works and base case in all aspects of condensate recovery, energy-saving, environmental concerning and economics.

Value Methodology Identifies Energy-Saving Challenges and Opportunities

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 197759, “Energy-Saving Challenges and Opportunities in Upstream Operations Using Value Methodology,” by Mohamed Ahmed Soliman, Saudi Aramco, prepared for the 2019 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. The objective of the complete paper is to investigate and analyze energy-saving and process-optimization opportunities in upstream surface facilities, from downhole to the gas/oil separation plants (GOSPs), using a value-methodology approach. Function analysis was used to identify those functions that can be reduced, eliminated, or synergized to minimize GOSP operating and maintenance cost. All successful opportunities were selected on the basis of their minimum operating expenses and capital expenditure (CAPEX) with a value-engineering methodology. Introduction Value methodology has been implemented successfully in new projects to save costs but rarely has been implemented in oil and gas operating facilities to minimize operating costs. The success of value methodology in reducing capital project costs prompted the author to explore its application to operating facilities, specifically toward minimizing operating and maintenance cost. Value methodology is used when value is a concern and requires optimization. Value is defined as the ratio of function to cost. The value-engineering methodology consists of the following six-step process (Fig. 1): Information: Collect, review, and analyze all information about the project or the plant, including the cost. Review and define current project conditions and identify study goals. Function analysis: Define the primary function of the product or project in a simple format. Creativity: Generate the largest number of innovative ideas (brainstorming) without being controlled by standards and best practices. Evaluation: Evaluate the ideas generated from the creativity phase, eliminate impractical ones, and select the most-profitable and -achievable improvement idea. Development: Develop further the selected best ideas from the evaluation phase and estimate the cost. The development phase includes cost/benefit analyses, drawings, implementation steps, and responsibilities. Presentation: Present the selected ideas to decision-makers and stakeholders for final approval. Case Studies Several energy-saving opportunities were analyzed to highlight the need to check continuously the function of each equipment item and process in any operating facility. Many functions were found to be unnecessary. In some cases, these unnecessary functions adversely affected plant operation. The complete paper provides four case studies; this synopsis will highlight three of them.

Benchmarking of Pulsed Field Gradient Nuclear Magnetic Resonance as a Demulsifier Selection Tool with Arabian Light Crude Oils

Summary The use of chemical demulsifiers in the treatment of crude oil emulsions is an essential step in processing facilities worldwide. Each production facility requires specific demulsifier reformulations as the crude characteristics change. The assessment of candidate demulsifiers before online field trials is currently done with bottle tests. Such tests are manual, based on water dropout visually measured by operators. The development of a method that can automatically determine the speed and amount of water dropout without the laborious need to manually record water separation would significantly decrease human error. Pulsed field gradient nuclear magnetic resonance (PFG-NMR) is used as a classification tool to qualitatively rank the efficiency of different demulsifiers in breaking Arabian Light emulsions. This imaging method can evaluate demulsifier action based on the emulsion characteristics; for example, rate of sedimentation and coalescence and formation of a dense packed zone (rag layer). The results are validated against field trials performed in gas-oil separation plants (GOSPs) at two Saudi Arabian facilities. There was good agreement between the PFG-NMR method and field trials. The results were found to correspond to the water dropout in the first stage of crude oil treatment in processing plants (production traps).

The Digitalization of Bottle Tests Nuclear Magnetic Resonance Evaluation of Emulsion Stability

Bottle tests are the preferred meth-od to test petroleum emulsion stability in the industry today. A new technique using nuclear magnetic resonance (NMR) is available to evaluate both stability and demulsification behavior of emulsions. The NMR scans the water fraction throughout the entire length of the emulsion sample. These rapid measurements are designed to dynamically probe the emulsion, capturing its separation as a digital image. This case study presents the ways NMR has helped predict the effects of future well line-up changes. Introduction Emulsion stability negatively impacts oil processing operations and plant design. The assessment of emulsion stability is performed at wellheads and gas/oil separation plants (GOSPs). Bottle tests are largely used for emulsion assessment, due to their simplicity and low cost. These tests depend on the visual identification of the separated water layer as the only quantifiable parameter. NMR is one of the alternative methods for emulsion assessment that can pro-vide information for all emulsion components. These components include the water layer; the oil/water interface - including the rag layer (the dense-pack zone [DPZ] of droplets above the interface); the remaining water-in-oil emulsion; and the dry-oil continuous phase. The DPZ - or rag layer - is of particular importance for oil processing, as its occurrence in separation vessels can lead to process upsets, resulting in excessive concentration of oil at the vessel’s water outlets. This interfacial phenomenon is particularly critical in the production of heavy oils, oils with high solid content, and oils forming highly stable emulsions. NMR is not only capable of measuring the water fraction throughout the entire emulsion sample, but can also provide a digital image of the water separating in the sample. More advanced NMR analyses are able to determine the water droplet size distribution (DSD) in the emulsion, and how the distribution changes during separation. It is also possible to obtain information on the droplet sizes at each position in the sample, as they change in time. Bottle tests are limited to the visualization of the free-water layer. Measurement errors are common if the oil/water interface is not clear. Unlike the NMR, any water still emulsified in the oil cannot be measured as it is not visible. The formation of the rag layer cannot be identified either. In addition, the efficiency of separation calculated from bottle test results, or emulsion separation index (ESI), requires knowledge of the water cut of the sample. The production water cut can be provided by the oil-processing operations, but the value is hardly the same found at sampling points. If the water cut is not known, it needs to be accurately measured in the sample after the bottle test. Usually the total amount of water is measured after centrifugation. It is difficult to guarantee that the emulsion is fully separated, as some droplets could still be unresolved at the interface. Another test limitation is the determination of separation efficiency when the water quality is poor. The presence of an oil-in-water emulsion could be the cause of cloudiness, contributing to an inefficient separation. But most of all, no readings can be made if the emulsion does not separate spontaneously. With NMR it is possible to determine the sedimentation rate of water droplets, even if no coalescence takes place (and no free-water layer is formed).

Size exclusion chromatography reveals a key parameter of demulsifiers for enhanced water separation from crude oil emulsions

Demulsifier is used in gas oil separation plants for the separation of water from crude oil emulsion. One of the important parameters for the enhancement of performance is the optimization of demulsifier formulation with respect to oil composition and produced water chemistry. The consistency in the quality of the formulation is essential to obtain the best separation of water throughout the production period of crude oil. The industry accepted method to optimize formulations is the bottle test method. However, this method remains laborious, time-consuming, imprecise, and requires access to fresh crude oil, which is not convenient from a practical viewpoint. Instead, routine physical and chemical properties are monitored to ensure the consistency of the demulsifier quality. It was, however, observed that there was a significant influence on the performance of a demulsifier from different batches with very close physical and chemical properties. Therefore, we developed a method using size exclusion chromatography to determine the molecular weight distribution of demulsifier base material, in this case, alkoxylated alkylphenol-formaldehyde resin. It was found that all the samples contained two well-separated species with one low molecular weight of about 2700 g/mol and other one with high molecular weight of about 15000 g/mol. The variation in the content of low and high molecular weight species was identified to be a key parameter significantly influencing the separation performance. It is apparent from this study that size exclusion chromatography could provide some additional insights on demulsifier intermediate chain length dispersity which could be correlated to actual separation performance.

Advances in alarm data analysis with a practical application to online alarm flood classification

During an alarm flood, the alarm rate is greater than the operator can effectively manage. Many alarm data analysis methods have been proposed in the literature to mitigate the impact of alarm floods. This paper gives a review of the state of the art in alarm data analysis and aims at structuring the field. A distinction between sequence mining methods that apply to alarm sequences and time series analysis methods that apply to alarm series is suggested. The review highlights that online applications to help the operators during alarm flood episodes have been only treated as sequence mining problem in the literature to date. To address this gap, the paper also presents a binary series approach to classify ongoing alarm floods based on a set of historical alarm floods. The motivation for a binary series approach is demonstrated through an industrial case study of a gas-oil separation plant, and the performance of the presented method is compared with the performance of an established sequence alignment method.

Online Alarm Flood Classification Using Alarm Coactivations

Alarms indicate abnormal operation of the process plants and alarm floods constitute specific abnormal episodes that cannot be handled safely by the operators. In that regard, online alarm flood classification based on a bank of past historical episodes provides support on how to handle ongoing alarm sequences. This paper introduces a new approach based on alarm coactivations that is appropriate for the analysis of ongoing sequences. The method shows improvements when compared to an established sequence alignment approach for abnormal episode analysis of a gas oil separation plant.

Arc-Flash Mitigation: A Systematic Approach for Company Standard Power System Schemes

Arc-flash hazard assessment studies involving a very large oil and gas company's equipment rated 38 kV and below revealed locations with excessive arcflash incident energy. After conducting many additional studies of power distribution systems for various plants (e.g., refineries, gas plants, gas-oil separation plants, and natural gas liquid plants), we realized that dangerous locations (greater than 40 cal/cm2) are somewhat consistent among various plant types. This knowledge makes planning and budgeting for implementing arc-flash mitigation predictable from a corporate perspective. Specific arc-flash mitigation techniques can be embedded in the specifications of new projects as well as company material standards to avoid unnecessary retrofit activities after installation. Maintenance personnel can also be effectively trained on arc-flash mitigation and safe work practices when consistent solutions are implemented. This article demonstrates a systematic approach to address dangerous arc-flash locations for corporate planning purposes and provides practical mitigation solutions that can be applied at many company facilities.

Detection and Quantification of Sulfate-Reducing and Polycyclic Aromatic Hydrocarbon-Degrading Bacteria in Oilfield Using Functional Markers and Quantitative PCR

Oilfield water samples from injection water treatment facility and soil/sludge samples from Gas Oil Separation Plant (GOSP) at Saudi Aramco were analyzed for the presence of SRB and PAH-degrading bacteria. SRB were detected by targeting a fragment of the apsA gene encoding adenosine-5-phosphosulfate reductase, which is characteristic of all SRB. The PAH-degrading bacteria were detected using a primer pair that amplifies a fragment of the gene encoding the large subunit of the naphthalene dioxygenase gene nahA. The nahA gene was detected in almost half of the soil/sludge samples with the highest copy number of 60540 copies/g soil/sludge. Most of the analyzed water samples contained high copy numbers of nahA gene with the highest copy number 3846 copies/ml. Most of the analyzed water samples revealed the presence of high copy numbers of the apsA gene with the highest copy number of 44 x 106/ml in sample number 2. Only 7 of the soil/sludge samples revealed the presence of the apsA gene with the highest copy number of 107920/g soil/sludge in sample number 11. In contrast to the nahA gene, the highest copy numbers of the apsA gene were detected in the water samples. SRB and PAH-degrading bacteria exist in some Saudi oilfields and appear to play a role in the H2S production and PAH degradation.

Large Synchronous Motor Failure Investigation: Measurements, Analysis, and Lessons Learned

In the oil and gas industry, large synchronous motors are used to drive water injection pumps to support the pressure of a reservoir and to maintain the production level of a reservoir over a longer period. Therefore, failures in such motors will have an adverse impact on operation and production. Even though synchronous motors are superior to induction motors in relation to system voltage regulation and power factor correction, their starting is more complicated. As a result, the application of synchronous motors requires careful engineering analysis in the design stage of a project to determine system requirements for a successful operation. This paper presents a failure analysis case study for three 11 000-hp synchronous motors at a gas–oil separation plant along with the starting issues faced prior to the occurrence of a permanent damage. The fundamentals of dynamic motor acceleration requirements to achieve a successful start will be reviewed. In addition, results of site measurements and subsequent computer simulation will be presented. The simulation results were substantiated by a failure root cause analysis report provided by the manufacturer. This paper also discusses the obstacles faced as a result of erroneous and limited data availability, and the approach to overcome such difficulties.

Complete Power Management System for an Industrial Refinery

Islanded power systems for critical facilities require a robust, secure, and reliable power management system (PMS) that can respond to system disturbances and avoid blackouts to ensure process survivability. A facility in Saudi Arabia with four gas-oil separation plants and one natural gas liquids’ recovery facility operates with a total installed generation capacity of approximately two gigawatts and no utility interconnections. This paper discusses PMS components, such as automatic generation control (power and frequency), volt/VAR control systems (reactive power and voltage), intertie power factor control, high-speed generation shedding, and runback, and high-speed load shedding, along with an overview of the overall system architecture and the state-of-the-art dual-ring time-division multiplexing synchronous optical network communications networks at this facility. High-speed generation-shedding and load-shedding systems are designed with overfrequency- and underfrequency-based secondary backup protection schemes to provide additional system reliability. This paper also introduces a transient-level computer model of the facility power system, which is used for functional testing of the PMS components.

A mixed integer linear programming model for the optimal operation of a network of gas oil separation plants

Inspired from a real case study of a Saudi oil company, this work addresses the optimal operation of a regional network of gas oil separation plants (GOSPs) in Arabian Gulf Coast Area to ultimately achieve higher savings in operating expenditures (OPEX) than those achieved by adopting single-surface facility optimisation. An originally tailored and integrated mixed integer linear programming (MILP) model is proposed to optimise the crude transfer through swing pipelines and equipment utilisation in each GOSP, to minimise the operating costs of a network of GOSPs. The developed model is applied to an existing network of GOSPs in the Ghawar field, Saudi Arabia, by considering 12 different monthly production scenarios developed from real production rates. Compared to rule-based current practice, an average 12.8% cost saving is realised by the developed model.

Risk-Based Process Safety Management through Process Design Modification for Gas Treatment Unit of Gas Oil Separation Plant

A new methodology for the feasible integration of process design and risk assessment is proposed using commercial simulators with the goal of carrying out risk-based process safety management of an existing gas oil separation plant (GOSP). For integration of these two different natures, the concept of static inventory was deduced in order to adjust the dynamic behavior of the fluid in process simulation to accident simulation, considering the flow rate and release duration of the fluid in case of an accident. Particularly for the gas treatment unit (GTU) among the various subsections of the GOSP process, this methodology attempts to assess the potential risk at the preliminary design stage and modify the process design of the existing process to alleviate the major hazard recursively identified during rigorous quantitative risk assessment (QRA). Consequently the modified design with different operation conditions reduces the total risk integrals by 27% at the expense of the additional $50,000 for capital cost. In addition, sensitivity analysis of total risk with respect to probability of success for the isolation process is carried out in order to give insight for a safer and more reliable process design.

Offshore Water-Disposal Wells: Formation Damage and Treatment

This article, written by Dennis Denney, contains highlights of paper IPTC 16595, ’Formation Damage and Treatment of Offshore Water-Disposal Wells in Saudi Arabia: Case Studies,’ by Ken Mei, Hassan B. Qahtani, Abdulmohsen S. Al-Kuait, and Luai A. Sukkar, Saudi Aramco, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. In one Saudi Aramco offshore oil field, the production from different platforms is transported to an onshore gas/oil-separation plant (GOSP) where the produced water is removed from the hydrocarbon stream. Then, the produced water is injected continuously into highly permeable formations through disposal wells. Therefore, the water-disposal system is an integral part of the hydrocarbon-recovery system. Failure of one of the disposal wells could affect oil production adversely. Introduction Field A is a mature oil field with more than 500 active producing wells, and it has been on stream for more than 50 years. The crude-oil-handling facility was built onshore with limited equipment capacity and a limited water-disposal capacity. The field produced formation water beginning in the 1980s, and the water cut has increased over time. This field is expected to continue operating at approximately full crude-oil-handling capacity, with all produced water to be dis-posed of continuously. The main focus is how to maintain the ability to dispose of all the produced water. Of the options studied, the best was to drill new water-disposal wells and to service existing disposal wells to maintain a high disposal capacity. Evaluation of the disposal capacity of each well is the core part of this option and is a major challenge associated with a water-disposal system. Well tests on water-disposal wells are uneconomical to conduct monthly. Also, water injection would have to be interrupted during testing. Another major challenge was determining an effective treatment for water-disposal wells that have encountered a significant drop in injection potential. The produced water contains a significant amount of waste material including solids, salts, chemicals, and residual oil. Even after being treated, the waste-water causes pipeline corrosion and formation damage. Conventional acidizing with hydrochloric acid (HCl) or mud acid (12% HCl+6% hydrofluoric acid) proved ineffective for treating the formation damage to improve injectivity. A new way was found for dealing effectively with injection loss caused by specific formation damage. Water-Disposal System The produced water passes through high- and low-pressure separators and then is pumped to the disposal wells by two injection pumps and a 24-in. above-ground pipeline. Because the water-disposal system is part of the hydrocarbon-recovery system, reduction of produced-water injection would restrict oil production. An increasing number of wells have electrical submersible pumps (ESPs) installed to produce fluid at higher rates, which accelerates water production. With new ESP wells coming on stream, in a few years the water volume will be two and one-half times the current produced-water volume.

The electrocoalescers' technology: Advances, strengths and limitations for crude oil separation

Water-in-oil emulsions are encountered in production, processing and transportation of crude oils. Their stability is an issue of great concern and economic relevance, impacting operations at several Saudi Aramco gas–oil separation plants (GOSPs). A number of technologies can be applied to destabilize emulsions, to meet the export specifications of maximum 0.3% water-in-oil and 10lbs per thousand barrels (PTB) of total dissolved salts in the crude oil. Among those technologies, electrocoalescence has the potential to reduce heating which is energy intensive. Electrocoalescence also limits the use of chemicals, which may contaminate the produced water.This paper summarizes some theoretical aspects and recent developments on electrocoalescence; experimental data are also provided to demonstrate strengths and limitations of this technology. Tests carried out in a laboratory flow loop equipped with an electrocoalescer package show that separation performances are poor when the emulsions' Reynolds number in the electric field zone is low and when the water droplet size distribution in the emulsion is centered at small diameters. As a consequence, the engineering studies for integrating an electrocoalescer package inside an existing separation facility should promote moderately turbulent emulsion flow condition to ensure that the technology will work efficiently.

In-Line-Water-Separation Prototype Development and Testing

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 137967, ’Inline Water Separation (IWS) Field Prototype Development and Testing,’ by J.J. Xiao, SPE, and Ramsey White, Saudi Aramco, and Shoubo Wang and Luis Gomez, Multiphase Systems Integration, originally prepared for the 2010 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 1-4 November. The paper has not been peer reviewed. A compact multiphase in-line-water-separation (IWS) field prototype system has been developed and tested. The system consists of a gas/liquid cylindrical cyclone (GLCC), a liquid/liquid pipe separator (LLPS), a liquid/liquid cylindrical cyclone (LLCC), and two-stage liquid/liquid hydrocyclones (LLHCs). The function of the system is to separate a significant portion of the produced water from a production stream while the remaining production fluids are sent to existing processing facilities. Introduction As oil fields mature, more water is produced with the oil and gas production. This is especially true when water injection is used to maintain reservoir pressure and increase oil recovery. A common production-water-handling strategy is centralized processing. In this scheme, production from individual wells is gathered to manifolds through flowlines and is transported to the gas-/oil-separation plant (GOSP) through large-diameter trunklines. At the GOSP, separation and processing of oil, gas, and water take place with large conventional vessels. The processed water is either disposed of at nearby water-disposal wells or sent back to the field for water reinjection into the reservoir. With increasing water production, several issues can develop: Water volume exceeds water-handling capacity of the GOSP, which can cause processed water to be off specification. The off-specification water in turn can lead to a decline in water injectivity, which may require regular stimulation treatments. Upgrade or expansion of GOSP water-handling capacity with conventional bulky separation systems can be costly. Existing gathering systems can become a bottleneck to oil production. To maintain oil production, the total fluid produced will increase as the water cut increases, and the gathering-system capacity will become a limiting factor. Laying extra flowlines or trunklines can be expensive, especially offshore. Wells can cease to produce because of increasing system backpressure as a result of the increasing water volume being transported through the gathering systems. Higher water production leads to higher chemical use (demulsifers and corrosion inhibitors) and, hence, higher processing cost. In addition, energy consumption will increase to transport large quantities of water from the field to the GOSP and then from the GOSP back for reinjection into the wells in the field. A number of methods are used to reduce the quantity of water produced to the surface. These methods include restricted production, cyclic production, mechanical or chemical water shutoff, and short-radius horizontal drilling. For new wells, the use of production equalizers and smart completions also can be viewed broadly as a way to control water production. The next-best place to handle water production is in the wellbore. However, downhole oil/water separation and reinjection still remain a challenge even after 20 years of industry research and development.

Designing and Testing a Chemical Demulsifier Dosage Controller in a Crude Oil Desalting Plant: An Artificial Intelligence‐Based Network Approach

AbstractThe aim of this paper is to present an artificial neural network (ANN) controller trained on a historical data set that covers a wide operating range of the fundamental parameters that affect the demulsifier dosage in a crude oil desalting process. The designed controller was tested and implemented on‐line in a gas‐oil separation plant. The results indicate that the current control strategy overinjects chemical demulsifier into the desalting process whereas the proposed ANN controller predicts a lower demulsifier dosage while keeping the salt content within its specification targets. Since an on‐line salt analyzer is not available in the desalting plant, an ANN based on historical measurements of the salt content in the desalting process was also developed. The results show that the predictions made by this ANN controller can be used as an on‐line strategy to predict and control the salt concentration in the treated oil.