Viability study of implementing smart/intelligent completion in commingled wells in an Australian offshore oil field

2009 ◽  
Vol 49 (1) ◽  
pp. 441
Author(s):  
Mahdi Nadri Pari ◽  
Akim Kabir
Keyword(s):  
Information Exchange ◽  
Simulation Software ◽  
Oil Field ◽  
Production Network ◽  
Reservoir Performance ◽  
Well Completion ◽  
Forecasting Performance ◽  
Reservoir Simulator ◽  
Simulator Program ◽  
Offshore Oil

Simulating the automated action of smart well components represents a challenge in forecasting performance of such wells, and is fundamental to design decisions. Examples are wells equipped with inflow control valves (ICV), where zones have to be switched on, off or partially closed based on their performance relative to the rest of the wells/completions in the field, and where they share the same surface network and facilities constraints. This paper presents a study that has been carried out to justify installation of a surface controlled ICV in a group of wells in an offshore Australian field with commingled production. The merit of surface-controlled ICV versus uncontrolled commingled production has been compared. A numerical reservoir simulator program has been used to model reservoir performance and production from individual zones. Also, the wells and production network have been simulated using well flow simulator and a production network simulation software respectively. A simulation manager software is used to facilitate information exchange between the two simulation programs (production network and reservoir) and optimisation of the process. Proper control of ICVs is simulated based on reservoir and wellbore simulation data, which will result in maximum oil production of a field network system resulting in higher recovery. Also, we have done economic analysis for smart well completion implementation. The results of two aforementioned analyses (simulation study and economics) show that smart completion is viable for this field.

Molecular diversity and abundance of the microbial community associated to an offshore oil field on the southeast of Brazil

2021 ◽  
Vol 160 ◽  
pp. 105215
Author(s):  
Araceli de Sousa Pires ◽  
Graciela Maria Dias ◽  
Danielly Chagas de Oliveira Mariano ◽  
Rubens Nobumoto Akamine ◽  
Ana Carla Cruz de Albuquerque ◽  
...  
Keyword(s):  
Microbial Community ◽  
Molecular Diversity ◽  
Oil Field ◽  
Offshore Oil

Unlocking Idle Production in an Offshore Sandstone Oil Field With Gas Hydrate Issues

2021 ◽  
Author(s):  
Babalola Daramola
Keyword(s):  
Gas Hydrate ◽  
Oil Production ◽  
Oil Field ◽  
Third Party ◽  
Flow Assurance ◽  
Well Testing ◽  
Production Wells ◽  
Oil Flow ◽  
Offshore Oil ◽  
Production Losses

Abstract This publication presents how an oil asset unlocked idle production after numerous production upsets and a gas hydrate blockage. It also uses economics to justify facilities enhancement projects for flow assurance. Field F is an offshore oil field with eight subsea wells tied back to a third party FPSO vessel. Field F was shut down for turnaround maintenance in 2015. After the field was brought back online, one of the production wells (F5) failed to flow. An evaluation of the reservoir, well, and facilities data suggested that there was a gas hydrate blockage in the subsea pipeline between the well head and the FPSO vessel. A subsea intervention vessel was then hired to execute a pipeline clean-out operation, which removed the gas hydrate, and restored F5 well oil production. To minimise oil production losses due to flow assurance issues, the asset team evaluated the viability of installing a test pipeline and a second methanol umbilical as facilities enhancement projects. The pipeline clean-out operation delivered 5400 barrels of oil per day production to the asset. The feasibility study suggested that installing a second methanol umbilical and a test pipeline are economically attractive. It is recommended that the new methanol umbilical is installed to guarantee oil flow from F5 and future infill production wells. The test pipeline can be used to clean up new wells, to induce low pressure wells, and for well testing, well sampling, water salinity evaluation, tracer evaluation, and production optimisation. This paper presents production upset diagnosis and remediation steps actioned in a producing oil field, and aids the justification of methanol umbilical capacity upgrade and test pipeline installations as facilities enhancement projects. It also indicates that gas hydrate blockage can be prevented by providing adequate methanol umbilical capacity for timely dosing of oil production wells.

Subsea Cable Applications in Offshore Oil Field Facilities

2013 ◽  
Author(s):  
Xiaodong Liang ◽  
John Stevens ◽  
Dwayne Kelly
Keyword(s):  
Oil Field ◽  
Offshore Oil

scholarly journals THE FATE OF TWO LARGE OIL SPILLS IN THE ARABIAN GULF

1983 ◽  
Vol 1983 (1) ◽  
pp. 377-380 ◽  
Author(s):  
William J. Lehr ◽  
Murat S. Belen
Keyword(s):  
Crude Oil ◽  
Computer Model ◽  
Trajectory Analysis ◽  
Oil Spills ◽  
Arabian Gulf ◽  
Oil Field ◽  
Environmental Damage ◽  
Unidentified Source ◽  
Offshore Oil ◽  
Large Sections

ABSTRACT In August and October 1980, two large oil spills occurred in the Arabian Gulf. The first, from an unidentified source, involved about 20,000 barrels of crude oil and impacted the entire north and west coasts of the island nation of Bahrain. The second occurred when the Ron Tapmeyer platform in the Hasbah offshore oil field blew out, releasing an estimated 50,000 barrels of thick crude into the Gulf. The spill subsequently covered large sections of the coastline of Qatar. The fate of the oil from these spills is examined with respect to the unique conditions found in the region. A computer model is used for trajectory analysis of the spills and hypothesizing the possible origin of the first spill. Methods of cleanup and problems with the weathered oil are mentioned. The environmental damage caused by the Bahrain spill is assessed.

scholarly journals Development of an analytical model to predict oil reservoirs performance using mechanical waves propagation

2021 ◽  
Author(s):  
Hesham A. Abu Zaid ◽  
◽  
Sherif A. Akl ◽  
Mahmoud Abu El Ela ◽  
Ahmed El-Banbi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Field Measurements ◽  
Field Trials ◽  
Oil Field ◽  
Reservoir Properties ◽  
Actual Performance ◽  
Reservoir Performance ◽  
Mechanical Waves ◽  
Incremental Oil Recovery ◽  
Wave Induced

The mechanical waves have been used as an unconventional enhanced oil recovery technique. It has been tested in many laboratory experiments as well as several field trials. This paper presents a robust forecasting model that can be used as an effective tool to predict the reservoir performance while applying seismic EOR technique. This model is developed by extending the wave induced fluid flow theory to account for the change in the reservoir characteristics as a result of wave application. A MATLAB program was developed based on the modified theory. The wave’s intensity, pressure, and energy dissipation spatial distributions are calculated. The portion of energy converted into thermal energy in the reservoir is assessed. The changes in reservoir properties due to temperature and pressure changes are considered. The incremental oil recovery and reduction in water production as a result of wave application are then calculated. The developed model was validated against actual performance of Liaohe oil field. The model results show that the wave application increases oil production from 33 to 47 ton/day and decreases water-oil ratio from 68 to 48%, which is close to the field measurements. A parametric analysis is performed to identify the important parameters that affect reservoir performance under seismic EOR. In addition, the study determines the optimum ranges of reservoir properties where this technique is most beneficial.

Overcoming Challenges in ESP Operation in Ultradeepwater Heavy-Oil Atlanta Field

2021 ◽  
Vol 73 (03) ◽  
pp. 46-47
Author(s):  
Chris Carpenter
Keyword(s):  
Heavy Oil ◽  
Oil Field ◽  
Primary System ◽  
Artificial Lift ◽  
Short Period ◽  
Production History ◽  
Electrical Submersible Pump ◽  
Water Cut ◽  
Available Information ◽  
Offshore Oil

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201135, “Challenges in ESP Operation in Ultradeepwater Heavy-Oil Atlanta Field,” by Alexandre Tavares, Paulo Sérgio Rocha, SPE, and Marcelo Paulino Santos, Enauta, et al., prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition - Americas, 10-12 November. The paper has not been peer reviewed. Atlanta is a post-salt offshore oil field in the Santos Basin, 185 km southeast of Rio de Janeiro. The combination of ultradeep water (1550 m) and heavy, viscous oil creates a challenging scenario for electrical submersible pump (ESP) applications. The complete paper discusses the performance of an ESP system using field data and software simulations. Introduction From initial screening to define the best artificial-lift method for the Atlanta Field’s requirements, options such as hydraulic pumps, hydraulic submersible pumps, multiphase pumps, ESPs, and gas lift (GL) were considered. Analysis determined that the best primary system was one using an in-well ESP with GL as backup. After an initial successful drillstem test (DST) with an in-well ESP, the decision was made, for the second DST, to install the test pump inside the riser, near seabed depth. It showed good results; comparison of oil-production potential between the pump installed inside a structure at the seabed—called an artificial lift skid (ALS)—and GL suggested that the latter would prove uneconomical. The artificial lift development concept is shown in Fig. 1. ESP Design ESP sizing was performed with a commercial software and considered available information on reservoir, completion, subsea, and topsides. To ensure that the ESP chosen would meet production and pressure boosts required in the field, base cases were built and analyzed for different moments of the field’s life. The cases considered different productivity indexes (PI), reservoir pressures, and water production [and consequently water cut (WC)] as their inputs. The design considers using pumps with a best efficiency point (BEP) for water set at high flow rates (17,500 B/D for in-well and 34,000 B/D for ALS). Thus, when the pumps deal with viscous fluid, the curve will have a BEP closer to the current operating point. Design boundaries of the in-well ESP and the ALS are provided in the complete paper, as are some of the operational requirements to be implemented in the ESP design to minimize risk. Field Production History In 2014, two wells were drilled, tested, and completed with in-well ESP as the primary artificial lift method. Because of delays in delivery of a floating production, storage, and offloading vessel (FPSO), the backup (ALS) was not installed until January 2018. In May 2018, Atlanta Field’s first oil was achieved through ATL-2’s in-well ESP. After a few hours operating through the in-well ESP, it prematurely failed, and the ALS of this well was successfully started up. Fifteen days after first oil, ATL-3’s in-well ESP was started up, but, as occurred with ATL-2, failed after a short period. Its ALS was successfully started up, and both wells produced slightly more than 1 year in that condition.

Evaluating the well integrity of old exploration wells as a risk factor for future storage projects – an example from the Troll field in the Norwegian North Sea

2021 ◽  
Author(s):  
Bastien Dupuy ◽  
Benjamin Emmel ◽  
Simone Zonetti
Keyword(s):  
North Sea ◽  
Early Stage ◽  
Numerical Models ◽  
Low Frequency ◽  
Oil Field ◽  
Finite Element Software ◽  
Well Completion ◽  
Well Integrity ◽  
Volumetric Assessment ◽  
Work Done

<p>More than 750 wildcat wells have been drilled in the Norwegian North Sea since 1966. Some of these wells could pose a risk for the environment, climate, and future H<sub>2</sub> and CO<sub>2</sub> storage projects by being preferred leakage paths for subsurface- and stored- gases (e.g., CH<sub>4</sub>, CO<sub>2 </sub>and/or H<sub>2</sub>). To ensure well integrity, these wells were secured by cement framing the well casing, and by building cement plugs at crucial positions in the well path before abandoning the well. However, in an early stage of exploration the geology of the subsurface was relatively uncertain, and the requirements for plug placing and how to abandon a well were not established and regulated. We analysed data relevant for the quality of a Plugging and Abandonment (P&A) work done on old exploration wells (1979 to 2003) from the Troll gas and oil field in the Norwegian North Sea. The data were extracted from public available well completion reports and the webpage of the Norwegian Petroleum Directorate. The dataset was analysed regarding their availability, plausibility and evaluated towards the present P&A regulations and geological knowledge for offshore Norway. Based on 12 criteria including reporting to the authorities, volumetric assessment of used cement quantities, position and length of the plugs in relation to reservoir- cap-rocks petrophysical conditions, and verification of the cementing job, a final P&A ranking of 31 exploration wells was established.</p><p>Parts of this data were used to build realistic numerical models of P&A'ed well to simulate electromagnetic responses using the finite element software COMSOL Multiphysics. Taking advantage of a dedicated implementation of low frequency ElectroMagnetics (EM), including effective formulations for thin electrical layers, it was possible to study the response of well components to external EM fields, both for the purpose of well detection and well monitoring. Results from the numerical models can be used as benchmark models in a realistic field scale well integrity monitoring approach.</p><p>In our presentation we will show results from the TOPHOLE project including realistic field distributions for different representative well configurations, examples of well detection and monitoring signals, and the ranking evaluation results.</p><p>Acknowledgments: This work is performed with support from the Research Council of Norway (TOPHOLE project Petromaks2-KPN 295132) and the NCCS Centre (NFR project number 257579/E20).</p>

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