Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23456, ’Jubilee Development Installation, Hookup, and Commissioning and Ready for Startup,’ by Laurent Culembourg, Kosmos Energy, Cory Weinbel, SPE, Anadarko Petroleum, Keith Mutimer, Tullow Oil, Frederic Chauvin, Technip, and Andrew McDonald, consultant, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed. The Jubilee Field Development, 60 km offshore Ghana, began Phase 1 production just 3.5 years after field discovery. Here is highlighted the successful execution of the in-country installation, hookup, and commissioning (IHUC) phase of the project in conjunction with operations readiness and assurance activities to bring the production system safely to an on-time ready-for-startup (RFSU) condition. Success was found through integration of a multipartner project team and the management of critical interfaces. Introduction The Jubilee partners, along with the Ghana National Petroleum Corporation (GNPC), decided to develop the field using a phased approach. The integrated project team (IPT) developed a plan to target just less than 300 million bbl in Phase 1 with a 17-well subsea system and a 120,000-BOPD floating production, storage, and offloading (FPSO) unit. Phase 1 was approved in Au-gust 2008, and first oil was achieved in November 2010. The overall project schedule was aggressive, with critical path activities occurring primarily within the IHUC phase of the project. Despite efforts to plan and meet the aggressive schedule, the IPT still encountered some significant challenges onshore and offshore Ghana during the IHUC phase. The key to resolving these issues successfully was linked with the execution strategy and the experienced team’s ability to develop a response plan and implement it successfully. IHUC Planning, Organization, and Execution Strategy The Jubilee Leadership Team (JLT) recognized that the IPT organization and interfaces with the unit operator needed to evolve with the progression of the project. As such, the development activities were divided into the following four phases, with governance models designed for each: Phase 1—FPSO construction and subsea procurement Phase 2—IHUC Phase 3—Startup Phase 4—Steady state Contracting Strategy and Resources A contracting strategy was put in place to favor IPT control over schedule imperatives with the following elements: Selecting world-class contractors with records of delivering on-time projects with excellent engineering Incentives for meeting, and penalties for failing to meet, critical milestones Separating the scope of umbilical, riser, and flowline (URF) activities that could be performed off the critical path from those that had to be done on the critical path and negotiating different incentives/penalties for each
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Africa Government > Ghana Government (0.34)
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 150635, ’Integrated Production Chemistry Management of the Schoonebeek Heavy Oil Redevelopment in the Netherlands: From Project to Startup and Steady State Production,’ by Andrew G. Shepherd, SPE, Stuart Mcgregor, and Ruud Trompert, Nederlandse Aardolie Maatschappij, and Sen Ubbels, Bob van de Gender, SPE, Theo van Ommen, SPE, and Sjoerd van der Knoop, SPE, Champion Technologies. The production chemistry management process undertaken during the design, commissioning, and startup of the Schoonebeek redevelopment faced challenging separation issues, saline water, and a multitude of other process conditions that resulted in a complex application portfolio. Chemical selection was conducted in adherence to health, safety, security, and environment (HSSE) directives and focused on unique produced fluid properties. Since startup, the success of chemical performance has come from the availability of chemical treatment programs and surveillance/sampling plans. So far, no contingency chemicals have been needed at the facilities. Introduction The Schoonebeek oil field was discovered in 1943 and operated until the late 1990s. A number of enhanced oil recovery methods were used in this field, including high- and low-pressure steam-floods, hot waterfloods, and in-situ combustion. The field is now being redeveloped, using low-pressure steam-flood with horizontal wells. Superheated steam, supplied by a combined heat and power (CHP) plant, will be injected into the reservoir through 25 wells adjacent to the production wells in 17 locations. Gross production will be evacuated from the reservoir through 44 horizontal wells in 18 locations using artificial lift pumps, with a casing vapor recovery (CVR) system included to improve the gross lifting capability. Production from each wellsite will be routed through a gross gathering system to the central treating facilities (CTF). The CTF will include the required facilities to separate the oil, water, and associated gas and treat the respective streams to export quality. Production Chemistry Management Compliance toward European chemical regulations (REACH) was one of main drivers for the short-listing of products to be applied in the Schoonebeek redevelopment. Schoonebeek crude oil has a relatively high API weight. Nevertheless, the crude oil is quite acidic, as seen in high total acid number and naphthenic acid values. Most (>90 wt%) of the naphthenic acids are in salt form, which means that they may affect oil/water separation. The crude oil also has very particular wax properties. A high cloud point and pour point indicate that wax precipitation and gelling in the facilities may become a problem during normal operations if not controlled. Furthermore, wax particles contribute to crude oil viscosity and also may affect separation. Fig. 1 presents an overview of the main chemical applications selected for treatment between the wellsites and the CTF and at the CTF itself, together with the main process vessels and streams.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14518, ’Virtual-Measurement Value During Startup of Major Offshore Projects,’ by R. Cramer, SPE, N. Griffiths, P. Kinghorn, SPE, and D. Schotanus, Shell Global Solutions; John Brutz, SPE, Shell USA; and Klaus Mueller, SPE, Shell Oman, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, rescheduled to 7-9 February 2012. The paper has not been peer reviewed. How can wells be managed optimally if one does not know continuously what they are producing? This problem is more critical at initial startup of the wells. Shell uses a real-time well virtual-flow-measurement tool, running on 60% of Shell’s global production, which has enabled significant added value in the areas of real-time surveillance and optimization. The virtual-flow-measurement tool has been applied in the startup of several of Shell’s offshore projects in the Arabian Gulf and in the Gulf of Mexico. Introduction Shell has several large upstream offshore projects in various stages of startup or commissioning. These projects have large capital investments and reserves contribution and a high degree of difficulty (e.g., very deep water, subsea processing, long subsea multiphase pipelines, and feeding large onshore gas plants). Hence, it is imperative to start up the processes as quickly and efficiently as possible, yet maintain the highest possible standards of technical integrity, safety, and environmental effects. Key aspects for efficient and effective project startup are well and reservoir surveillance and hydrocarbon accounting. It is important to know how much the wells are producing and the composition of the fluid streams to maximize production and for flow assurance, asset technical integrity, and accounting purposes. Ideally, this would be achieved by use of multiphase flowmeters (MFMs) on each well to measure the oil, gas, and water flows physically and continuously, or by routing each well progressively to a test separator as the wells are started up. However, at the time of startup, MFMs may not have been installed for all wells, and for wells that do have them, they usually are not yet commissioned because MFM commissioning requires fluid samples from the wells, and for subsea wells, sampling usually is performed robotically and at a later stage of startup. Virtual flow meters (VFMs) can be operational when production begins. Similarly, test separators may not be commissioned at the time of initial well production, and if they are operational, they are not suitable for tracking production from multiple wells. Hence, virtual flow measurement has significant value for well/reservoir surveillance and hydrocarbon accounting from initiation of startup to the time when MFMs are effectively commissioned and, thereafter, as effective insurance in case of individual-meter failure.
- Asia > Thailand > Bangkok > Bangkok (0.25)
- Asia > Middle East > Oman (0.25)
- North America > United States > Texas (0.15)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 640 > Tonga Field > Tahiti Well (0.98)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 640 > Tahiti Field > Tahiti Well (0.98)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 640 > Caesar Field > Tahiti Well (0.98)