Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract Brownfield project performance When a new facility starts up, a new brownfield site is created. Through technology improvements we are able to get more production out of our existing assets and getting access to new frontiers is increasingly complex. These factors raise the importance of doing brownfield projects well. But, the schedule and cost slippage that is often found in capital projects is significantly worse for brownfield projects. Typical issues in brownfield projects Project cost growth and schedule slippage often occurs in the early phases of the development. Project and asset teams may lock themselves into pre-determined solutions for brownfield projects without spending sufficient time on the front end loading, driven by an attitude of already knowing what needs to get done. Surprises appear during execution because of a lack of understanding of the facilities, such as its current condition, the process constraints and the restrictions to execute the projected work. Estimates and schedules can grow because they were based on analogues or factors, which turn out to be unreliable due to the unique nature of each brownfield project. Best practices Due to their many interfaces and complexity, brownfield projects require discipline: to spend time to truly understand the asset, to get sufficient detail early to develop a realistic estimate and schedule, to appoint experienced operators to support the project team at the early stage of the project, to allocate sufficient funds to perform high quality front end loading and to plan the work in detail once in the field. New technologies can improve brownfield projects outcomes, e.g. laser scanning, 4D execution planning, novel inspection techniques and advanced data management. This paper will explore what best practices reduce complexity and improve performance. Through proper framing, dependencies with other work on the asset can be minimized and this reduces the risk of delays. Transferring work from the live construction site to an offsite fabricator will lead to less safety exposure, better quality and a more predictable schedule. Performing trial fits prior to shipment further reduces the risk of execution inefficiencies. Recognition The recognition of the inherent complexity and challenges associated with brownfield projects at all levels of the company, will lead to better consistency in execution of this projects. Experience with executing brownfield projects and with the particular facility is a pre-requisite. Being successful at extending the life of our existing assets will then bring large rewards.
Remote passive acoustic monitoring (RPAM) is a new technology that enables the acoustic monitoring of marine mammals from an onshore location. Acoustic data are transferred in real time via satellite link from an at-sea passive acoustic monitoring (PAM) system. From anywhere in the world, an RPAM operator can detect, listen to, and track vocalizing whales and dolphins, potentially reducing the number of operators at sea.
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
- Health, Safety, Environment & Sustainability (0.96)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.95)
- Data Science & Engineering Analytics > Information Management and Systems (0.95)
Abstract Technology remains at the forefront in taking the Oil and Gas industry forward and will provide solutions to future challenges. Companies adopting new technologies to solve existing problems will answer upcoming challenges facing the industry, especially those that provide significant cost savings and increase safety levels. With the safe operation of onshore and offshore oil and gas assets always having top priority, together with high demands placed on Operators to increase production and maximize returns, increasingly the industry is using Unmanned Aerial Vehicles (UAVs) to inspect process plants that are generally inaccessible during normal operations. The latter typically comprises online onshore and offshore flare systems, towers and columns, flare support structures, splash zones and underdeck areas. UAV technology is an innovative, safe and highly cost effective way to perform inspections without the need to shut down the facility, especially with regard to online flares when traditionally the only way to inspect them was visually during a shut-down. The major drawback with the latter is that any problems with the flare could only be identified during the shut-down and (unless operators held a stock of spare parts for these bespoke units), it would be necessary to re-commission the flare system and operate it for a further period until replacements had been delivered hence causing the expense and inconvenience of an additional shut-down. Splash zone and underdeck inspections require specialist rope access teams, scaffolding and relatively calm weather conditions. The major drawbacks here are manpower levels, bedspace on assets and duration to set-up and disassemble equipment required to undertake and assist with inspections. UAVs are increasingly being used by international Oil and Gas operators to inspect flares and other process plants whilst online so that a replacement tip and/or spare parts can be ordered in advance, or any necessary remedial work identified and planned in a controlled and coordinated manner prior to a planned shut-down. UAVs are also used routinely for preventative maintenance inspections in splash zone and underdeck areas.
Offshore Europe Stories about the future of the North Sea oil business often talk about this pioneering offshore basin in the past tense. A recent one from the Petroleum Economist, headlined “Growing old gracefully,” described the future there as “squeezing out the last drops.” The global oil and gas industry is feeling the pain of the oil price plunge, but the UK feels it more acutely. Exploration drilling is at rock bottom levels, the offshore UK Continental Shelf is one of the world’s most expensive from which to produce a barrel of oil, and investment spending is expected to drop sharply in coming years. When it comes to new technology development, the North Sea is known as a global testing ground for advances in well plugging and platform removal. The pessimistic talk has served as a rallying cry for much needed change. “Do not waste the crisis,” said John Pearson, who chairs the Efficiency Task Force created by the industry group, Oil & Gas UK, to seek ways to lower the cost of North Sea exploration. “We have got a golden opportunity. Let’s not waste it.” He delivered his call for action at a presentation at the recent SPE Offshore Europe Conference & Exhibition in Aberdeen where Oil & Gas UK released its 2015 economic report that showed the problems there go deeper than the oil price collapse. “If there was no action, it [North Sea output] would shrink. But the plan is to take concerted action,” said Angela Seeney, director of technology, supply chain, and decommissioning at the Oil & Gas Authority (OGA). The authority was created this year by the UK government as part of an effort to revive North Sea exploration and production. The actions also include significant tax reductions, and free, high-quality seismic images of frontier areas. The OGA has a dual mandate of regulating the business and maximizing the ultimate recovery of the country’s oil and gas reserves. The call for change began before the collapse of oil prices with the release of the Wood Review early last year. The report warned that the UK offshore industry could face “irreversible damage” if prompt action was not taken to address its problems. Since then, the government and the industry have taken a rapid series of actions to follow the report’s recommendations to ensure the maximum economic recovery of North Sea reserves. Statoil North Sea Discovery Moves Toward Production Statoil is going to work to put its enormous Johan Sverdrup discovery into production, showing that even one of the most explored parts of the North Sea still has significant potential. The find in the heart of a cluster of fields in the Norwegian sector of the North Sea is expected to produce up to 650,000 B/D, said øivind Reinertsen, senior vice president for Johan Sverdrup field development, in a briefing on the project at SPE Offshore Europe. “We are in a very, very mature area in the Norwegian Continental Shelf,” he said, adding that the find in 2010 was one of the largest there since the 1980s, with 1.7 billion bbl to 3 billion bbl of recoverable oil. Statoil is pushing the pace of development at a time when low oil prices leave scant margin for development cost inflation. While the Norwegian national oil company is still engineering and signing contracts on the first phase of the project, it has begun work on the second phase to meet a tight 2022 deadline to start increasing the output from 315,000 B/D to more than 550,000 B/D, or one quarter of Norway’s oil output. The discovery and the project in one of the oldest offshore plays are indications that there is still much to be learned about the rocks and what it takes to manage the cost of a megaproject. Thinking Differently is Easier Than Doing Differently There is no shortage of ideas for reducing the cost and risk of offshore oil and gas developments. The hard part is implementing them in an industry where they require changes in long-standing habits, corporate cultures, and some new technology. Offshore UK has become a testing ground for doing things differently because the high cost of exploration and production there is jeopardizing its future. “We have got to get about 40% out of our cost base really, really quickly,” said John Pearson, who chairs the Oil & Gas UK’s Efficiency Task Force, which is responding to the problem that has spawned a variety of initiatives. The task force has pointed out the need for using more standardized equipment and designs as a way to reduce the risk of cost overruns, blown deadlines, and malfunctioning systems. This will require a change in the habits of engineers working for operators that are used to specifying even small details in the equipment ordered. Pearson said the added cost often falls short of any improvement in performance. Endgame in the North Sea Inspires Creative Thinking In a down market, plugging and abandoning North Sea wells looks like an opportunity. The cost for operators is reduced because the government is paying more than half of the cost of the work, and many service companies hungry for work are offering discounts. “Companies are capitalizing on the downturn by dealing with plugging and abandoning wells,” said Grant Johnston, a project engineer for Helix Well Ops at SPE Offshore Europe. “A lot of companies have dead wells that need to be sorted out. There are savings to be had.” Oil & Gas UK has predicted that decommissioning spending will rise from USD 1.5 billion last year to USD 2.3 billion this year and USD 3 billion by 2018. “The scale of some of the decommissioning projects to be undertaken on the UK Continental Shelf over the next decade has not been seen before anywhere in the world,” said the Oil & Gas UK 2015 economic report.
- Europe > United Kingdom > North Sea (1.00)
- Europe > North Sea (1.00)
- Europe > Netherlands > North Sea (1.00)
- (2 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Europe Government > United Kingdom Government (0.48)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 9/11b > Mariner Field > Maureen Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 9/11b > Mariner Field > Heimdal Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 9/11a > Mariner Field > Maureen Formation (0.99)
- (75 more...)
Seismic Data New generation of seismic promises big advances Selling new offshore seismic survey methods can be reduced to two goals: “We want more of everything at less cost.” That maxim was offered by Andrew Long, chief scientist of geoscience and engineering, imaging, and engineering for Petroleum Geo- Services, one of the players in this intensely competitive, economically depressed, technology-driven business. While the science behind using sound waves to image underground formations is baffling to outsiders, the two avenues for doing it better are not. There are improvements in data acquisition covering sound sources, receivers, and survey methods. And there is the mathematics and computer power needed to process and extract more information from the constantly growing amount of data gathered. Faster, Better Seismic Surveys by Making Many Sounds at Once The pace of a seismic survey can be measured by the number of shots taken per day. Huge onshore surveys have shown that allowing 10 or more sound sources working at the same time without any coordination can drastically reduce the time needed to gather data over a large area, and get better data as well. “One of the biggest surprises is we have gotten almost universally better data from our simultaneous source surveys,” said Craig Beasley, a Schlumberger Fellow and chief geophysicist at WesternGeco. More data are gathered from more angles for a more accurate picture of what is below, said Beasley, who explained that one flashlight can help you see in a dark basement, but it is better with two and more is better. The Hunger for the Lowest Frequencies Takes Data Gathering in New Directions The word “broadband” is used to sell a lot of what is new in offshore seismic. It can mean different things depending on who is speaking. But most often, it is applied to things used to gather scarce signals at the lowest frequencies. Gathering more low-frequency data is the “holy grail’ in broadband, said Craig Beasley, chief geophysicist at Western- Geco, which is part of Schlumberger. They are valuable for determining rock properties and imaging deep formations. Seemingly small gains can be big. “Moving down from “3 to 1.5 (Hz) does not sound like a lot. But in octaves, it is a whole other octave,” he said. Intractable Problem and Big Payoff Sell a Seismic Acquisition Innovation The Mad Dog field was a major discovery for BP in the late 1990s, but developing it looked like a high-risk proposition. The problem was the field was an early discovery beneath the thick layer of salt covering much of the deepwater US Gulf of Mexico. Shooting seismic through the salt resulted in murky images that increased the risk of development wells that produced little or nothing, which could turn a 4-billion-bbl field into a marginal investment. BP needed to solve the problem because it had leased a large number of deepwater blocks where the industry was drilling a growing number of dry holes due to poor subsurface imaging. “It was pretty common knowledge in the industry that you have this problem. But what are you going to do about it?” said John Etgen, a distinguished advisor in seismic imaging at BP. The problem is salt distorts sound waves as they travel down and are reflected back up. The salt is like broken eyeglasses. It acts as “big, very complex lens distorting the sound waves.”
- Europe > United Kingdom > North Sea (0.29)
- North America > United States > Gulf of Mexico > Central GOM (0.24)
- Europe > Norway > Norwegian Sea (0.24)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 826 > Mad Dog Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 825 > Mad Dog Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 782 > Mad Dog Field (0.99)
- (3 more...)
A special characteristic of a career in geophysics is the close exposure to fieldwork, an aspect that brings special challenges for many. In this opportunity, “Full Spectrum” would like to showcase the success stories of women geophysicists who have worked in service companies and faced the fieldwork (and more) with their own approaches.
- Personal (0.68)
- Instructional Material > Course Syllabus & Notes (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Education > Educational Setting > Higher Education (1.00)
- Oceania > Papua New Guinea > Papuan Peninsula > Central Province > National Capital District > Petroleum Retention License 15 > P’nyang Field (0.98)
- Oceania > Papua New Guinea > Papuan Peninsula > Central Province > National Capital District > Petroleum Retention License 15 > Elk-Antelope Field (0.98)
- Oceania > Papua New Guinea > Papuan Peninsula > Central Province > National Capital District > Petroleum Retention License 15 > Angore Field (0.98)
- (9 more...)
Abstract Multi-zone single-trip (MST) technology is a completion method to perform sequential sand-control treatments to multiple zones in one trip down-hole. The primary advantage of the method is the operational efficiency and resultant cost-savings. The paper presents the challenges surrounding the latest one of five Gulf of Mexico wells installations in an Ultra-Deepwater project, describes the systems used and presents their key factors of success. For the first time, an intelligent well completion was successfully installed together with the MST system, further improving the producing capabilities to collect reservoir information and to manage fluid production. The paper also discusses the technological advantages of the MST completion method, key lessons learned to date and the major success factors in the project specific to the completion operations. The paper is structured around well integrity, operational efficiency and completion excellence. Well integrity is accomplished by ensuring that completion components conform to the extreme downhole well conditions, maintain well control; and keep zone isolation during high-pressure frac-pack treatments. Operational efficiency was attained by clear guidelines, right personnel involvement, identifying and eliminating any possible operational risk. Completion excellence was achieved by system built-in redundancy features for flawless executions and software modeling to simulate downhole conditions from installation through production phases. The intelligent completions capability and the value added to the system are also presented.
Abstract Risk Management approach is an essential part of the project. Large industries and particular companies incorporate RM Culture. Statistics shows, that companies with Project Management (PM) Structure reduce cost ineffectiveness up to 20%. In oil and gas industry PM Risk Analysis (PRMA) has been widely used for the last years. Various models and procedures have been developed to manage projects of different scale. Nonetheless, Offshore Projects (OP) complexity, high uncertainty of technical, financial, market and government factors, as well as different sea conditions, still makes sense to improve general PRMA models according to the oil and gas OP features. Traditional RM tools and techniques are not appropriate to cope with complex projects in the Arctic. Companies will have to modify risk assessment process or look for new methods. The paper suggests OPRMM, where the attempt to implement PM tools and techniques together with mathematical modeling and expert assessment is made and institutional factors are included. Practically, it is founded on the comparison between offshore field development in the Barents Sea and the Kara Sea. The reason for research is debates around future Arctic oil and gas projects and their commercial potential. Several large projects with participation of major international companies in the Barents Sea and the prospectivity of the Kara Sea Projects in conditions of technology difficulties are under discussion and have not reached the investment project phase yet. OPRMM starts with identifying the key factors, which could affect offshore field development. Inside the investment regime modified real option value (ROV) model for OP is developed: stop option and scale transformation option. Basing on the binominal trees and Monte Carlo Simulation it is possible to see the perspectives of the OP at an early stage in the conditions of high uncertainty. Incorporating the ROV model into investment regime allows operator to choose the territory to explore. The research shows, that offshore projects in the Arctic offshore is not only under the pressure of internal corporative factors, but also under influence of external institutional factors. New tools and approaches will be required in Arctic projects where no one wants to be looking in the wrong place.
- Europe > Russia > Kara Sea (0.46)
- Asia > Russia > Kara Sea (0.46)
- North America > United States > Alaska (0.28)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Overview > Innovation (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.94)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Europe > Russia > Barents Sea > East Barents Sea Basin > Shtokmanovskoye Field (0.99)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug > Purovsky District > West Siberian Basin > Central Basin > Tazovskoye Field (0.99)
- (8 more...)
Abstract Objective/Scope In Q4 2012, the 8” Teal dynamic riser required replacement. A project team was assembled to remove the existing riser and install a replacement. The riser was originally installed in the 1990's by divers based on the Anasuria Floating Production Storage Offloading (FPSO). The FPSO facilities that were used to provide diver access into the chain table area to secure the bend restrictor were no longer operational. Previous diver intervention at the chain table had experienced high levels of non-productive time, so a remote removal method to cut and lower the riser and bend restrictor to the seabed was pursued. Methods, Procedures, Process The project team initiated a concept study to set the challenge to release the riser from the FPSO remotely to a) reduce HSE risk; b) de-risk project by separating release campaign from recovery campaign and c) perform the work offshore using a very small team (FPSO bedding constraints was one of the reasons the team didn't use an air dive team to do it from the FPSO). The concept selected was largely based on a method used for removal of other similar risers in 1999 albeit that all that remained from that campaign was a PowerPoint presentation. The majority of engineering calculations and drawings could not be located. Results, Observations, Conclusions The tooling was designed, fabricated and tested in less than 6 months from award of contract to offshore operations. During the offshore campaign, various issues were encountered (e.g. incorrect ‘as built‘ documentation) but the remote removal campaign was a success with both the riser and its bend restrictor being removed from the FPSO without requiring any diver intervention, thus reducing the project costs and HSE exposure. Novel/Additive Information Lessons learned from the offshore campaign are being captured with the concept being further refined to allow the removal of the riser and bend restrictor without first having to cut and remove the topside riser end fitting. This should reduce the offshore operational time for any future riser removals and remove the risks associated with unknown internal condition of the riser.
Abstract Chemical EOR technologies used offshore can either be short term reservoir conformance treatments such as Marcit Gels for near-wellbore and BrightWater® for in-depth permeability modifications or long term floods such as mobility control improvements utilizing polymers (latex emulsion or powder). Each offshore EOR technology has significant logistical challenges for successful implementation that ultimately impacts the oil recovery performance. This paper will present a project management plan and logistics using existing offshore facilities, which needs to be considered well in advance of project execution for a successful field implementation for both conformance and mobility control programs. Synthetic polyacrylamides for offshore mobility control applications are limited in practice but interest in offshore applications is increasing rapidly. Polyacrylamides are commercially available in two forms, latex emulsion (liquid) and powder. Each product form has unique benefits and challenges for effective field execution that will be discussed here. The project execution management plan encompasses global supply chain activities (logistics, imports, regulatory) as well as design, construction, and installation of custom facilities. In addition, field execution requires detailed project management including safety and HazID visits, pre-job site visits, pumping services, and surveillance programs. This management plan can be furhter complicated by the type of completion (i.e., dry or wet tree), chemical tie-in location to water injection, neat or slipstream chemical injection, deck space for injection equipment and chemical base tanks, hydration or inversion equipment, and size of transport vessel for chemical transfer offshore. Offshore EOR projects are not generally planned during initial field development. Rather, EOR projects are considered add-on technologies that have to fit existing facilities and operations. This add-on approach increases the complexity and risks of EOR projects and Offshore Operations. Lessons learned and some tools that we have utilized to plan and implement offshore chemical EOR projects are discussed.
- Europe (1.00)
- North America > United States > California (0.46)
- Asia > Middle East > Qatar (0.28)
- South America > Brazil > Rio de Janeiro (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Salema Field (0.99)
- North America > United States > California > Ventura Basin > Sockeye Field (0.99)
- North America > United States > California > Monterey Formation (0.99)
- (23 more...)