Optimal Planning and Scheduling of Offshore Oil Field Infrastructure Investment and Operations

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.

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Subsea Cable Applications in Offshore Oil Field Facilities

10.2118/166558-ms ◽

2013 ◽

Cited By ~ 1

Author(s):

Xiaodong Liang ◽

John Stevens ◽

Dwayne Kelly

Keyword(s):

Oil Field ◽

Offshore Oil

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Optimal Planning and Scheduling for Repetitive Construction Projects

Journal of Management in Engineering ◽

10.1061/(asce)0742-597x(2006)22:1(11) ◽

2006 ◽

Vol 22 (1) ◽

pp. 11-19 ◽

Cited By ~ 78

Author(s):

Khalied Hyari ◽

Khaled El-Rayes

Keyword(s):

Construction Projects ◽

Optimal Planning ◽

Planning And Scheduling

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THE FATE OF TWO LARGE OIL SPILLS IN THE ARABIAN GULF

International Oil Spill Conference Proceedings ◽

10.7901/2169-3358-1983-1-377 ◽

1983 ◽

Vol 1983 (1) ◽

pp. 377-380 ◽

Cited By ~ 2

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.

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

Journal of Petroleum Technology ◽

10.2118/0321-0046-jpt ◽

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.

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3-D Seismic Evidence of Tertiary - Cretaceous Karsts and Cretaceous Marine Channels from Offshore Oil-Field in Abu Dhabi and Outcrop Analogs from United Arab Emirates

10.3997/2214-4609-pdb.248.136 ◽

2010 ◽

Author(s):

Raed El-Awawdeh ◽

Naeema Khouri ◽

Majid H. Al Suwaidi ◽

Mathew P. Williams ◽

Jie Zhang ◽

...

Keyword(s):

United Arab Emirates ◽

Oil Field ◽

Abu Dhabi ◽

Offshore Oil

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