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Researchers Gain Insights Into Microbial Succession in Offshore Wells
Joel Parshall, JPT Features Editor
Researchers from Shell and Newcastle University in the United Kingdom, in collaboration with the US Department of Energy (DOE) Joint Genome Institute (JGI), have obtained valuable insights into the succession of microbial populations in multiple oil wells drilled in a North Sea field. Findings from the research could influence future industry practices.
Microbes play an important part in maintaining the earth’s biogeochemical cycles and are known to have displayed a very successful adaptive capability in extreme subsurface conditions when they are relatively stable.
The Shell-Newcastle University research focused on the response of microbes to the disruption of their environment caused by well drilling and production-related activities and the microbial impact on reservoir production.
New Study Shows Stanching of Decline in Oil Reserves, Revenue
Stephen Whitfield, Senior Staff Writer
With the release of Ernst & Young’s (EY) 2017 US oil and gas reserves study, the services firm hosted a presentation in which a panel of its analysts discussed trends among independent and integrated companies within the industry. Along with oil and gas reserves, the panel examined trends in capital expenditures (Capex) for exploration and development activities as well as other performance metrics.
A key takeaway from the EY study was that prices are trending lower than in recent history and volatility in price is somewhat subdued. Capex totaled $85.7 billion in 2016, 27% lower than in 2015 and 57% lower than in 2014. The study said that the oil price has stabilized at a “new normal,” and that this stabilization has helped limit the flow of ratings downgrades and reserve revisions from 2015 to 2016. The US Energy Information Administration (EIA) expects the country to see a 4% growth in oil production in 2017.
Total Acquires Maersk Oil in $7.5-Billion Deal, Boosts North Sea Presence
Pam Boschee, Senior Editor
Total will acquire Maersk Oil for $4.95 billion in Total shares and will assume $2.5 billion of Maersk’s debt. The deal will expand Total’s global holdings to approximately 1 billion BOE of 2P/2C reserves, of which more than 80% are in the North Sea. Total said that the combination of its and Maersk’s assets in the North Sea is expected to “generate operational, commercial, and financial synergies” of more than $400 million per year. Closing of the deal is expected in 1Q 2018.
Included in the Maersk North Sea holdings are interests in Johan Sverdrup (8.44%) and the Culzean gas condensate field (49.99%). At the end of 2Q, Culzean’s project completion rate was 55%, ahead of the expected 48%. Maersk reported in July that the gas export and condensate pipelines had been laid and all three jackets installed on the field. High-pressure/high-temperature drilling began in July. Production is expected to start in 2019.
Demand for Raw Fracturing Sand Set for Healthy Growth
Joel Parshall, JPT Features Editor
Demand for raw fracturing sand is forecast to increase by more than 4% per year to almost 100 billion pounds in 2021, according to a recently released study by industry research firm, the Freedonia Group. In value terms, raw fracturing sand is expected to grow at a 10% annual rate to more than $3 billion in 2021, which reflects substantial gains in average prices and volume levels.
The study, Proppants in North America, presents historical data from 2006, 2011, and 2016. It forecasts to 2021 by type—including raw fracturing sand, resin-coated sand, and ceramic proppant—and market location in pounds and US-dollar values. The study also evaluates key industry players.
Raw sand demand is expected to grow in the United States and Canada, with the US being the principal user at a market share of 88% in 2016, the study said.
Bidding Interest Drops for Gulf of Mexico Leases
Joel Parshall, JPT Features Editor
Oil industry interest in obtaining new offshore acreage in the US Gulf of Mexico (GOM) showed a significant decline in the mid-August federal outer continental shelf lease sale, compared with the previous sale in March.
US GOM regionwide Lease Sale 249, held by the Bureau of Ocean Energy Management in New Orleans, drew 99 bids from 27 participating companies, with high bids totalling $121 million.
The value of all bids received was $137 million for 90 blocks, a decline of 57% in bid value and 45% in block acreage from Central Lease Sale 247 on 22 March. That sale reflected the first increase in industry leasing activity in federal GOM waters in 5 years.
The fabrication of structures for Arctic applications is expected to face major challenges when it comes to the fracture toughness of the heat affected zone and the weld metal. Although the initial base metal toughness may be excellent, a severe toughness deterioration normally occurs as result of the rapid heating and cooling cycles in welding. The present investigation addresses tensile behavior and toughness properties of 32 and 50 mm thick 420 MPa plates, including tensile testing at both room temperature and −60°C, and Charpy V impact toughness and CTOD fracture toughness at −60°C. The welds were deposited by gas shielded flux cored arc welding using a heat input of 2-2.4 kJ/mm. The results showed a dramatic reduction in the fracture toughness after welding, i.e., from CTOD level above 2.5 mm to below 0.25 mm for the 50 mm plate, and from ~ 2 mm to the lowest value of 0.12 mm for the 32mm plate. The Charpy V toughness appeared to be good for the 50 mm, both for the heat affected zone and the weld metal, while the 32 mm plate suffered from low values in the weld metal root area. The results for the 50 mm thick plate are very promising, particularly for use in the temperature range down to −20 to −40°C.
The oil and gas industry is moving north due to the large oil and gas reserves. For example, a preliminary assessment by the US Geological Survey suggests the Arctic seabed may hold as much as about 30% of the world's undiscovered gas and 13% of the world's undiscovered oil (Gautier et al, 2009), mostly offshore under less than 500 meters of water. In these areas, the temperature may occasionally fall below −30 to −40°C, which represents new challenges to the materials. Normally, structural steels and pipelines may easily satisfy toughness requirements at such low temperature. However, welding tends to be very harmful to low temperature fracture toughness. Both the heat affected zone (HAZ) and the weld metal may fail in providing sufficient toughness (e.g., Akselsen et al, 2011; Østby et al, 2011; Akselsen et al, 2012; Akselsen and Østby, 2014).
Last December I had the pleasure of returning to the Kingdom of Saudi Arabia and touring the giant Manifa oil field. Manifa produces a heavy, sour crude oil from six, long (up to 40 km), stacked reservoirs in shallow water (Arukhe 2014). The shallow waters have abundant sea grasses and corals and are teeming with marine life. Shrimping and fishing are important parts of the local economy. The development of the Manifa field is a fascinating story showing how creative solutions can minimize impact on the environment.
Manifa was discovered by Saudi Aramco in 1957. The discovery well targeted both the shallower formations productive in the large Safaniya coastal field and the deeper Arab formations so productive onshore. Neither zone was productive; however, the discovery found excellent productive layers in between, including three that were only produced in small volumes onshore and three that had never before proved productive. The heavy, sour crude was similar to Khursaniyah, one of the three major types of crude present in large quantities in the Kingdom. Demand was less for this crude than for Safaniya and Arab crudes but the market for heavy sour crudes was improving (Aramco World 1963). The first development was in 1962, and the field was brought on stream in 1964. The field produced for 20 years before being mothballed in 1985 because of low demand (Aldossary 2015).
Manifa’s history can be contrasted with that of Prudhoe Bay in Alaska. While specific reserve estimates for Manifa are not public information, both fields are very large. The Prudhoe Bay field was discovered in 1968 and did not begin production until 1977. Prudhoe production peaked at about 1.5 million BOPD in 1989. Prudhoe Bay crude averages 27.6 °API and had a significant domestic market to serve. Manifa crude is 26–31 °API and has from 2.8% to 3.7% sulfur content (Croft and Patzek 2009), with less of a market at the time. It is fairly astonishing that roughly comparable fields would go down such radically different paths.
Manifa would remain mothballed until 2006. Saudi Aramco redeveloped the field consistent with a very long life production time horizon for its large reservoirs (Saudi Aramco 2016). But the old way of approaching shallow offshore fields would not be acceptable.
The use of jackup rigs in these shallow waters would have required excessive dredging, and the size of the reservoir eliminated the possibility of effective development from the shore. A new approach to development would be needed. A creative plan to develop man-made islands connected by a causeway would allow conventional onshore rigs to be used to develop this offshore field.
A long causeway was considered, but early designs would have decreased water circulation vital to distributing nutrients and oxygen vital to marine life. With more than 4 million man-hours of work in the design phase, a solution was developed to build 27 man-made islands connected by 41 km of causeways. To ensure needed water circulation, the causeway does not go all the way across the bay and 14 bridges were built into the causeway to further improve circulation (Aldossary 2015). Production commenced in 2012 ahead of schedule and under budget in a development that earned a UNESCO Environmental Responsibility Award nomination.
It is an impressive development of which Saudi Aramco is rightly proud, with eventual production capacity of 900,000 BOPD or more. As our helicopter approached the massive processing facility, I looked at the three large flare stacks. There was nothing being flared. Was the field shut in? No, the design and normal operations of the field use all of the produced gas and creative operations practices mean that almost no gas is flared. Excess electricity produced by the facilities goes into the power grid.
Whoever thought the “drilling process” of “fracking” would be making headlines? In a tour of hydraulic-fracturing operations, ironically in a fossil-fuel-powered vehicle, Yoko Ono was trying to draw attention to the horrors of the process. Of course, no one on the tour actually lived there, owns property there, or has a degree in hydrology, geology, or petroleum engineering. I also found out, after 30 years in the industry, that I am a driller, because every article I read describes hydraulic fracturing as a drilling process. Nothing against my drilling brethren, but I have prided myself over the years in being a completion engineer; and fracturing is just one part of the completion process. Who knows, maybe a prominent mainstream-media editor will read this editorial and realize that they have stated it wrong. Maybe they will read the papers and realize that there is a lot of research and smart technical work that goes into developing these unconventional resources and that no one in the industry would design a fracture to contaminate our groundwater (if they even could).
It is sad but accurate that most people who are against hydraulic fracturing are speaking from emotion and fear. Recently, I went with a group of experts to Washington to speak to the Bureau of Land Management and the White House about the technical details of hydraulic fracturing and wellbore integrity. Except for a few within the bureau, most with whom we met and who will develop our energy policies do not understand hydraulic fracturing. They listened intently, told us they wanted to do the right thing for the country, and thanked us for coming to speak to them. But, just imagine how many people, both good and bad, come to talk to them about hydraulic fracturing. In a way, they are placed in the tough situation of “whom do I believe?”
The United States desperately needs a coherent energy policy. As part of a national energy policy, more regulatory oversight will inevitably come. The best scenario for the energy industry is open-minded regulatory development that relies on existing knowledge from the industry. In years past, the industry largely automatically opposed regulations; instead, the industry should be helping shape regulations and ensuring that regulations are developed in coordination with industry input. Suggestions for how this can be accomplished include commenting on notices of proposed rulemaking, inviting regulators to industry conferences, and providing industry experts to regulatory bodies on a fellowship basis. The consequences of not influencing fracturing regulations are that regulations that eventually result may be harsher than necessary, unduly burdensome, more costly, and ultimately result in less oil and gas reserves for our country.
Meanwhile, let us continue what we have accomplished. We are pulling the US nearer to energy independence, creating domestic jobs, and learning new techniques and practices. Let us stay open to new ideas and be safe while doing it.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 152621 Case History of the Fayetteville Shale Completions by J. Harpel, Southwestern Energy, et al.
SPE 152509 A New Approach for Numerical Modeling of Hydraulic-Fracturing Propagation in Naturally Fractured Reservoirs by R. Keshavarzi, Islamic Azad University, et al.
SPE 155779 Hydraulic-Fracturing Design and Well-Production Results in the Eagle Ford Shale: One Operator’s Perspective by Lucas W. Bazan, Bazan Consulting, et al.
SPE 162916 Comparison of Hydraulic-Fracturing Fluids in Multistage-Fracture-Stimulated Horizontal Wells in the Pembina Cardium Formation by Meghan Klein, Sproule Associates, et al.
Abstract Open hole, multi-stage (OHMS) fracturing systems were introduced in 2001. Since then, this technology has been credited with unlocking oil and gas reserves around the world that were previously dismissed as unavailable or uneconomic, enabling companies to maximize production in tight rock formations and mature oil fields. OHMS systems have been run in every type of formation from the much heralded shale gas plays in North America to the massive carbonate formations in Saudi Arabia and have also been used in offshore wells in the North Sea, Black Sea and West Africa. This paper focuses on the open hole packer used in OHMS systems to generate the annular compartmentalization necessary for effective multi-stage stimulation and production. This packer is a dual element, hydraulic-set, mechanical (DHM) packer and provides reliable open hole isolation with various benefits compared to swellable, inflatable and other mechanical packers including: 1) Reduced torque and drag due to their short length (average 5 ft) with only two short sections of rubber with a minimum running outside diameter, 2) Creation of two independent sealing points via dual elements, which together act like a single, 3 ft long seal with redundant sealing, 3) No need to formulate them for specific downhole fluids or wait for them to swell, 4) No thermal contraction such that the seal is not lost during stimulation, and 5) The rubber element does not reduce its durometer rating when set. Laboratory testing and field applications of the DHM packer are presented including HPHT, multi-laterals, proppant fracturing and acid stimulation with on and offshore case histories incorporating stand alone screens, acid jets, fracture ports and combinations thereof.
In many companies, it is necessary to review all active wells individually at least once a year. These reviews are commonly called lease reviews, and are used to look for potential optimization projects, mechanical problems, re-completion candidates or identify potential wells to be plugged and abandoned. Normally those meetings include all engineering departments, geology and field people who know the day-to-day operations of almost every well. Reserves update efforts are no different from a lease review; however, in many companies only the reservoir engineers are in charge of updating reserves. We believe the same team that decides the optimization plan for each individual well during the lease review should be involved during the reserves update process. Decisions like changing reserves classifications must be considered by the entire asset team; including the geologist, production engineer, operations personnel and the financial analyst. Reservoir engineers usually lead the reserves update process in most companies. This paper is focused on the workflow for tight gas reservoirs where smooth data is scarce and many factors such as hydraulic fractures, liquid loading, multi-layer systems and differential depletion affect the reserves analysis. In this environment, the need for teamwork is essential.
The challenges of meeting future energy demand, the latest has improved in the past decade is a myth. In fact, drilling advances in upstream technology, and the growing importance of efficiency in wells more than 10,000 feet deep and for gas wells has conventional and unconventional natural gas supplies in the world not improved, perhaps because technology is not being efficiently energy mix highlighted the general and technical sessions at the employed, he said. Attendance at the annual conference Technical Sessions totaled 8,061. The technical sessions covered all of SPE's technical disciplines. The conference's opening general session brought together Seventy technical-paper sessions and five panel discussions covered experts from a variety of points of view to discuss the myths and a wide range of new applications and ideas, as well as case histories realities surrounding future energy supplies.
This paper was prepared for presentation at the 1999 SPE Hydrocarbon Economics and Evaluation Symposium held in Dallas, Texas, 20-23 March 1999.