OE staff reports from the Offshore Technology Conference in Houston on Tuesday, 5 May 2015.
Vietnamese delegates addressed challenges and opportunities in fractured basement reservoirs on Tuesday morning’s “Understanding the Challenges of Vietnam Fractured Basement Exploration, Drilling, and Production” session.
Dung Tien Pham, president and CEO of PetroVietnam Drilling and Services, told OTC attendees that although Vietnam has a large presence in fractured basement reservoir, granite basement drilling has taken them to the most difficult environments.
“These hard and abrasive areas present challenges in drilling performance, because they predominately consist of granite, such as high rocks. Moreover, due to weathering and fracturing, the rocks have no primary porosity,” Pham explained.
However, despite the complicated geology, there are exploration investment opportunities within these areas as well, highlighted Dr. Nguyen Tien Long, exploration VP, PetroVietnam Exploration and Production.
“Most of Vietnam’s oil production comes from the Cuu Long Basin. This important basin consist of over 935 drilled wells, in which 500 were drilled in the granite basement. The basement consists of approximately 3.37 billion bbl of potential crude,” he concluded.
-Audrey Raj
The US government-funded institution, Research Partnership to Secure Energy for America (RPSEA), is currently undertaking seven new projects to add clarity, remove risk, and measure and improve the effectiveness of deepwater oil and gas operational fluid measurement systems. The group of projects, known as RPSEA Projects 10121-4304-01, began in July 2012 and is expected to be completed by December 2015.
“This research will close the gaps in fluid measurement of subsea operations,” said Jim Leavens, an engineer with Soape & Associates. “The measurement of errors of consequence is rarely random, but is systematic.” Even small errors in measurement can result in catastrophic and unforeseen consequences, he said. Therefore, if new and innovative measurement technologies can detect unsafe conditions, then the industry must put them to use, or “shame on us,” Leavens said. The group of research projects is conducted in partnership with Chevron, ConocoPhillips, GE, Statoil and Total.
The first project is a new subsea sampling system that is meant to provide fluid properties for multi-phase flow meters.
The second project is a deepwater subsea insertable sensor, which can insert a sensor into the flow stream. The system can insert and track up to four sensors per unit.
The third project is a deepwater subsea clamp-on measurement meter that can be clamped on to the outside wall of a subsea pipeline to verify flow rates. The clamped-on meter uses electrical capacitance tomography to image and measure fluid flows.
The fourth project is a deepwater seabed kick detection system to detect small mud density changes due to reservoir fluid inflow. The system uses ultrasonic and gradiometric sensors and riser adapters to detect mud density before kicks occur.
The fifth project is a new type of downhole differential pressure sensor used to achieve a true differential pressure measurement at downhole conditions. The unit is designed for use in 15,000psi and 250°C environments.
The sixth project is to evaluate existing virtual flow meters. The project will test the virtual flow meters in real world conditions in moderate to difficult field scenarios to test their effectiveness and accuracy.
The seventh project is meant to detect subsea meter fouling due to erosion or scaling conditions.
Gaps in deepwater flow measurement can have serious consequences to safety and economics, Leavens said. “And the deepwater environment amplifies their importance.”
He noted that although people might “get disgusted” by some government projects that seem destined to waste taxpayer funds, these projects that use taxes for support are resulting in “money well spent."
-Jeannie Stell
Technip CEO Thierry Pilenko joined his counterpart from FMC Technologies at the FMC Technologies booth this morning to discuss two two firms' new joint venture, Forsys.
Thierry says research by the firms showed that Forsys could make 30% potential capital cost savings on subsea development projects, even before they start working more closely on integrating technology and simplifying interfaces.
But, said Pilenko, in a panel discussion with FMC Technologies CEO John Gremp, operators would need to play their part.
"What is key here is the rules of engagement. The idea is for engagement to start from scratch, with an open mind and with respect for the information and technology and the safety constraints on a project."
"Operators have to change their business model," says Gremp. "And they need to be open minded and with the current environment they are willing to do things differently."
The two said the idea for Forsys, which brings together the two vendor companies as a front end engineering house which is also involved life of field, came about over a year ago, before oil prices slumped, because of the need to reduce the high prices of subsea developments, not least in deeper waters.
-Elaine Maslin
When and by how much the oil price rebounds has been a common discussion point at this year's OTC.
Speaking this morning during a breakfast session, held in the Galleria area by Norway's NCE Subsea, Andrew Paterson, from OTC exhibitor Infield Systems, said: "Our view is that average oil price for this year will be $63/bbl, next year we think in $70s, rising to $90.
"We are a seeing a slowing in the reduction of forecast spending in this period," he continued. "We do think we are reaching the end of the bottom and there are some positive numbers."
According to a recent straw poll by Infield of oil industry professionals mostly from operators, he said the majority think the market will recover in 1-2 years.
-Elaine Maslin
BP discussed its global technology strategy and programs at an OTC session on 6 May to highlight the work the company has been doing in three specific areas: enhanced oil recovery (EOR), digital monitoring, and advanced seismic imaging.
BP said the company is a leader in the EOR industry for two reasons: According to independent information, BP has the highest light oil EOR production in the world, producing more than any other international oil company, largely because of its heritage gas injection EOR in Prudhoe Bay, and because the company brings new technology to the industry, particularly LoSal.
With the digital oilfield, BP has a set of three advisors to streamline the process. BP said that in the construction phase, its well advisor helps pull well data into a useable format to drill and complete the wells more efficiently. Then BP moves to a phase of well operations with a series of advisors and consoles to pull existing well data into consoles to useable formats, so well operators can produce more efficiently and optimize production.
Its third set of advisors focuses on operations and integrity.
Eric Green, BP lead on advanced seismic imaging, said that everything BP does in subsurface from exploration through late field life is dependent upon the seismic image that they have.
BP has been and strives to be a leader in seismic imaging, focusing on two areas: seismic reservoir characterization and seismic imaging and modeling.
Examples Green gave include trialing and deploying wide azimuth towed streamers (WATS) acquisition in the Gulf of Mexico, and pioneering the development of ocean bottom seismic nodes for complex subsalt imaging.
-Melissa Sustaita
Petrobras credits its success in offshore pre-salt exploration and production (E&P) to innovative technologies and lessons learned, said Solange de Silva Guedes, director of E&P and chief upstream officer for Petrobras. Guedes made her comments to a full-house crowd at this week's Offshore Technology Conference.
On 4 May 2015, Petrobras counted 12 production units and 55 wells in its pre-salt plays. As of 5 May, the company added another production unit, bringing the total to 13. The pre-salt plays were managed into two phases to date.
“Phase 0 was about information gathering,” Guedes said. “Phase 1a is about production and development.” Phase 1b includes plans for further development and production while implementing cost reductions, further standardization, enhanced productivity and other improvements, she said.
In March 2014, the pre-salt assets were producing 395,000 bpd via 5 production units, but that has since increased to 737,000 bpd in February 2015. The company saw a 54% time reduction to production from 2010 to 2014. Petrobras contracted 25 drilling rigs from 12 suppliers to drill 130 wells, and “all lessons learned were shared between all the drill crews and all contractors,” Guedes said.
“We included strategies, risk management and innovative technologies at the beginning of these projects. Our top five productive wells were each more than 30,000 bpd.” Further innovations will help Petrobras reach its goal of 1 MMbpd by 2017, she said.
Specifically, Petrobras would like to use improved technologies in the areas of reservoir characterization, higher floating production unit processing capacities, lower completion decouplings, ocean-bottom sensors, intelligent completions, high-pressure separation, manifolds, flexible pipes, subsea trees, nano-technologies and controlled salinity water injections systems.
“An accelerated learning curve will be applied,” she said. “The importance of these optimization programs will continue as the pre-salt campaign moves forward.” As a result of its extensive use of cutting edge technologies, standardizations, sharing best practices and continuous improvement, Petrobras saw it 2014 operational efficiencies in pre-salt plays improve to an average of 92.4% during the past three years.
“We credit a lot of this to our business partners. Our relationship with our business partners is based on mutual respect and openness,” Guedes said.
-Jeannie Stell
Subscribe
