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Techbits From 15 to 16 October, more than 120 oil and gas professionals converged in Bergen, Norway for the fourth SPE Norwegian Petroleum Technology Conference (PTC). The conference, which was held in conjunction with Norway's Offshore Technology Days Exhibition, allowed managers, engineers, and business development planners to discuss how Norway plans to maintain its status as a global energy technology leader and incorporate innovations from companies big and small, far and wide. "The conference was really focused around StatoilHydro's dominant role in the Norwegian oil and gas industry and how they plan to ensure continual development of new technologies and put them to use," said Jan Roar Drechsler, Chairperson of the PTC Program Committee and the SPE Stavanger section, as well as a Principal Engineer and Technical Representative for Completions with StatoilHydro. "In the past [prior to the merger of Statoil and Norsk Hydro], there was a sort of competition between Statoil and Hydro to be first in the development of a new technology. There is concern that now some development programs, either within the company or with different partners, might be put aside or altered. People wanted to know how these would go on in the future." The first two presenters elaborated on this concern by outlining the role of technology in developing the reserves on the Norwegian Continental Shelf (NCS) and the dangers of scaling back future technology development programs. Roy Ruså, Vice President of Technology for Petoro, discussed upcoming technology challenges for operators and service providers in his talk "Technology Critical—Do We Act Accordingly?" Ruså pointed out that the mature NCS province still has many significant business opportunities, but they are linked to even greater technical challenges, such as realizing remaining reserves from smaller prospects, reducing nonrecoverable reserves, and finding and developing new recoverable resources. He acknowledged StatoilHydro as the major driver of technology development on the NCS, but added that the company must continue making significant investments in R&D and increasingly diversify its portfolio of production solutions by pulling in more technologies from other industries and geographic regions.
Techbits A distinguished panel of operating company representatives assembled earlier this year to share their views on how hydraulic fracturing is being applied today, and what challenges must be overcome to achieve further gains. The panelists took part in the plenary session "Hydraulic Fracturing: Think Global But Act Local" at the SPE Hydraulic Fracturing Technology Conference 2009 in The Woodlands, Texas. Stephen Holditch, Department Head and Samuel Roberts Noble Foundation-endowed Chair in Petroleum Engineering at Texas A&M University, moderated the plenary. He opened with a discussion of the so-called "resource triangle" theory that states that hydrocarbon resources are distributed log-normally in nature, with easily developed conventional reserves—which are a relatively small portion of overall volume—located at the top of the triangle. "As you get deeper into the resource triangle [closer to the base], the amount of unconventional resource plays is tremendous," Holditch said. A method developed at A&M to evaluate the ratio of conventional to unconventional resources in a basin suggests that there is approximately 10 times more technically recoverable oil and gas from unconventional resources than from conventional reserves. This method was developed from data-rich basins in the US Rockies region, but Holditch is confident that this same ratio should be found in basins around the world. "We are looking at more basins with this technique, and if the 10-to-1 [unconventional to conventional] ratio holds up, this means there is an enormous amount of unconventional resources yet to be produced around the world," he said. "Technology transfer on techniques such as hydraulic fracturing will be key to unlocking these resources." Kirk Bartko, Senior Petroleum Engineering Consultant with Saudi Aramco's Petroleum Engineering Support Division, spoke next about his company's stimulation efforts in Saudi Arabia. He said that as of 2006, the country had more than 5% of the world's known gas reserves with 230 Tcf. "Domestic demand is 7 Bcf per day, and by 2025 this is expected to grow to 14 Bcf per day due to increasing industrial requirements and electricity generation," he continued.
The energy industry is at the start of an unavoidable renaissance, driven by increased globalization of E&P, the development of a multicultural workforce, and the increased need for data on demand. This was the message of the SPE 2007 Digital Energy Conference and Exhibition, held in April in Houston. The 2-day event was organized through SPE's Gulf Coast section Digital Energy Study Group. The conference began with a focus on current successes in implementing digital technologies in the workplace and what technology is needed going forward. Charlie Williams, Chief Scientist of Well Engineering and Production Technology, Shell International E&P, gave the first keynote address, describing how Shell has implemented digital technologies in its field operations with particular emphasis on "smart fields." An executive roundtable that followed brought together executives from operating and technology companies to discuss business drivers in the E&P community and the types of supporting technologies that have been developed to address these drivers. The luncheon keynote was delivered by Phiroz Darukhanavala, BP Vice President and Chief Technology Officer of Digital and Communications Technology. "Knowledge, computing power, and technological evolution are exploding at such a rate that we are seeing a blurring of boundaries between the physical world and the digital world," he said. These advances are evident on the Internet and in fields such as aviation, and the oil and gas industry has been swept up in this digitization as well. "It's happening upstream and down, from the initial exploration efforts to drilling to production, refining, transportation, and out to the customer's gas tank," he said. Darukhanavala pointed to several current examples of how digital advances affect daily operations. One is in so-called smart drilling, being able to run an analysis at the rigsite and get the results in minutes vs. having to capture mud samples, send them to a laboratory, and wait 2 to 3 days for results. Other examples include being able to quickly measure production flow rates, wirelessly monitoring the working condition of rotating equipment, and seamlessly tracking the location and movements of rail cars and other transportation vessels. While all of this digitization has resulted in an exponential growth in the amount of information available to make informed decisions, Darukhanavala warned that it might be too much of a good thing. "With this deluge of data, the question becomes, How do we manage it and not drown in it? In my opinion, a data plug is almost as bad as a data drought, and even more expensive for the business," he said.
Techbits Pau, France was the scene for a recent SPE Applied Technology Workshop (ATW) titled "Managing Naphthenates and Soap Emulsions." From 10–13 March 2008, more than 70 attendees discussed the flow assurance challenges that naphthenate deposition presents, as well as the current state of the art in mitigating their formation in the field. Colin Smith, senior consultant with Maxoil Solutions and ATW Committee Member, opened the workshop with a scene-setting discussion on the fundamentals of naphthenate sludge and emulsion formation. If left unchecked, naphthenate deposits may cause fouling or plugging of production equipment such as flowlines and separators, and the formation of stable emulsions may prevent efficient oil/water separation, increasing separator residence times. The problem is more common than the industry might think, according to Smith; naphthenate deposits are present in 10% or more of North Sea crudes, while 30% of southeast Asian crudes and 20% of west African crudes demonstrate soap emulsion or sludge problems. Smith mentioned that naphthenates were first clearly identified in oilfields in the 1960s, but research and development (R&D) efforts began in earnest in the mid-1990s. The first session of the workshop highlighted the fundamentals. Johan Sjoblom, Professor at the Norwegian University of Science and Technology (NTNU), examined the current understanding of the different types of acids in a crude oil that can lead to naphthenate formation and sludge or emulsion problems. Monoacids (those acids with one carboxyl [COOH] group) tend to stabilize emulsions and concentrate in the oil phase or sludges, while tetracids (those with four COOH groups) can stabilize oil/water emulsions and tend to react with metallic ions such as calcium (Ca) to form deposits that harden irreversibly. Christian Hurtevent, an expert in physical chemistry and deposits with Total, discussed his company's experience with emulsion formation based on oil density and acid type. In general, Total has observed biodegradation and deposit problems in problem crudes with lower API values (<30), while higher API problem crudes tend to demonstrate emulsion stability challenges. The company has used an ultrasonic scanner to evaluate emulsion phase behavior, which has suggested how various naphthenic salts aggregate in a crude oil/water mixture. Ingemar Uneback, Application Development Manager for Akzo Nobel, proposed how derivatives of naphthenic mono acids could be extracted from crude oil and used as favorable starting blocks in chemical synthesis. In the formation of surfactants, for example, several monoacids demonstrate excellent surface active properties, low viscosity, good oxidative stability, and favorable biodegradability for environmentally sensitive applications. Uneback stated that Akzo Nobel has begun testing naphthenic monoacids as surfactants with promising results for potential application in fuels, agrochemicals, oilfield process chemicals, and asphalts.