|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Production operations in the offshore artic regions are within the reach of existing technology. Procedures used onshore and offshore in less hostile regions, however, must be modified to meet the challenges of the harsh climatic conditions in the remote locations. In the last decade, the major area of industry interest has been the offshore region of Alaska and Canada. The environmental conditions vary significantly in each of these regions. The specific production system that is selected must be tailored to each unique combination of these factors to ensure safe oilfield development.
Drilling automation differs from rig automation. Instead of mechanized or automated machinery that deals with surface processes, drilling automation is centered on the downhole activities necessary in the actual drilling of an oil or gas well. Today, this involves the linking of surface and downhole measurements with near real-time predictive models to improve the safety and efficiency of the drilling process. SPE volunteers formed the Drilling Systems Automation Technical Section (DSATS) in 2008. The purpose of DSATS is to accelerate the development and implementation of drilling systems automation in well construction by supporting initiatives which communicate the technology, recommend best practices, standardize nomenclature and help define the value of drilling systems automation.
ExxonMobil is looking to secure a semisubmersible to complete the drilling of a deepwater wildcat in the Flemish Pass offshore eastern Canada. The operator began drilling the Hampden K-41 probe in the spring of last year using Seadrill semisubmersible rig West Aquarius, but the unit was pulled off the well soon thereafter for reasons unknown. ExxonMobil is currently prequalifying companies to supply a mobile offshore drilling unit to continue the well at Hampden in Exploration License (EL) 1165A. The operator is targeting a mid-year 2022 start to the probe to be drilled in around 1175 m of water, some 454 km from St. John's, Newfoundland. Meanwhile, China's CNOCC has wrapped up drilling on its Pelles prospect, its first exploration well offshore Newfoundland. The prospect, in about 1163 m of water, is located within license EL 1144.
Michael Eberhard, an SPE Distinguished Service Award recipient and former director of the SPE Rocky Mountain Region, died 23 June. Eberhard started his 40-year oil industry career as a field engineer for Halliburton Services. He went on to become the company's Rocky Mountain Technology Manager from 2004 to 2011 and led a multidisciplined team focused on unconventional resources completions and optimization. He was the completions manager for Anadarko Petroleum's DJ Basin program from 2011 to 2015. He joined SRC Energy in 2015 and was the COO and executive vice president of the company.
Recent field studies have shown that measurements taken with aerial light detection and ranging (LiDAR) are more effective in discovering various sources of methane emissions than onsite optical gas imaging (OGI) and that policy and regulations that rely on OGI surveys alone risk missing a significant portion of total emissions. While emissions reduction depends on the frequency, distribution, and magnitudes of source types, recent field studies have shown that a small proportion of sources or sites is responsible for most methane emissions and that measured emissions significantly exceed estimates, often by 50% or more. A recent paper published by Environmental Science & Technology presents how researchers are using the disparity in these estimates to sharpen inventory estimates at upstream oil and gas sites. Traditionally, the differences between estimated and actual emissions have been attributed to what are called "fugitive" emissions from leaking components detected by optical gas imaging (OGI) cameras. Some disagreement exists, however, as to what constitutes fugitive vs. vented sources and, if the source is vented, what is considered normal vs. abnormal venting.
Cold heavy oil production with sand (CHOPS) recovery processes generate large volumes of sand that must be managed. In Canada in 1997, approximately 330,000 m3 of sand (approximately 45% porosity sand at surface) were produced from CHOPS wells. Individual wells may produce as much as 10 to 20 m3/d of sand in the first days of production and may diminish to values of 0.25 to 5 m3/d when steady state is achieved. Sand grain size reflects most of the reservoir. There is little sorting or segregation in the slurry transport to the well; however, not all zones in the reservoir may be contributing equally at all times.
Steam assisted gravity drainage (SAGD) is an outstanding example of a steam injection process devised for exploitation of heavy oil or bitumen reservoirs utilizing horizontal wells. It is widely used in Alberta Canada, Russia, and China for recovery of heavy and extra-heavy oilsands resources. Several variations of the basic process have been developed, and are being tested. The original SAGD process, as developed by Butler, McNab, and Lo in 1979, utilizes two parallel horizontal wells in a vertical plane: the injector being the upper well and the producer the lower well (Figure 1, taken from Butler). If the oil/bitumen mobility is initially very low, steam is circulated in both wells for conduction heating of the oil around the wells.
A ruling by Mexico's Energy Secretariat, or SENER, this month has made the national oil company Pemex the operator of the contested Zama field that was discovered by Houston-based Talos Energy in 2017. The companies have been in dispute over the shallow-water Zama prospect since 2018 after Pemex claimed that the discovery was a contiguous reservoir that extends into its offshore block. Independent reserves audits commissioned by each company have supported their own claims, with Talos' audit showing that 60% of the reservoir's estimated 670 million BOE fell within its block. Pemex estimates that its block represents 50.4% of the Zama reservoir. In statement issued 5 July, Talos lamented the decision and highlighted that it has drilled four wells in the Zama field (one exploratory, three delineation wells) and has demonstrated to Mexican authorities its ability to operate the unit.
Figure 1.6--The Baldpate Compliant Tower is one of the tallest free-standing structures in the world – Empire State Building (right) for comparison (Web Photograph, Amerada Hess Corp., New York City). Figure 1.9a--Worldwide fleet of installed and sanctioned semisubmersible FPS (courtesy of BP). Figure 1.9c--Worldwide fleet of installed and sanctioned spars (courtesy of BP). Figure 1.10--Semisubmersible FPS planned for the Thunder Horse field (courtesy of BP). Figure 1.11--Alternative proven technology field development options (courtesy of BP). Figure 1.12--Subsea production trees used in conjunction with a fixed jacket structure (Intec Engineering, Houston).
Introduction Heavy oil is defined as liquid petroleum of less than 20 API gravity or more than 200 cp viscosity at reservoir conditions. No explicit differentiation is made between heavy oil and oil sands (tar sands), although the criteria of less than 12 API gravity and greater than 10,000 cp are sometimes used to define oil sands. The oil in oil sands is an immobile fluid under existing reservoir conditions, and heavy oils are somewhat mobile fluids under naturally existing pressure gradients. Unconsolidated sandstones (UCSS) are sandstones (or sands) that possess no true tensile strength arising from grain-to-grain mineral cementation. Before 1985, heavy-oil production was based largely on thermal stimulation, ΔT, to reduce viscosity and large pressure drops, Δp, to induce flow. Projects used cyclic steam stimulation (huff'n' puff), steam flooding, wet or dry combustion with air or oxygen injection, or combinations of these methods.