Total is determined to push ahead with its plans to drill for oil in the Amazon basin, it said on 1 June as Greenpeace activists interrupted its annual general meeting in protest over the project. An audit of the Martin Linge project was conducted by the Petroleum Safety Authority Norway (PSA) on 28–30 March 2017. This was directed at technical safety, electrical equipment, maintenance management, and Total’s own follow-up of technical barriers during the commissioning phase.
Considering most of the rigs deal with human-machine interface systems, the role of human factors is at the heart of any successful operation. Eye-tracking technology can be useful in real-time operation centers where ocular movement data can improve the professionals’ performance. What is the reality of risk in the hydrocarbon sector? In this roundtable discussion, senior industry executives discuss what happens when process safety intent meets the reality of operations. InterMoor, an Acteon company responsible for mooring, foundations, and subsea services, has completed its 10th straight year of operation without any lost-time incidents.
On 21–22 March, The Petroleum Safety Authority Norway (PSA) held the Arctic Safety Conference. Now, the PSA has made several of the presentations available for download. The Norwegian model for managing safety in the petroleum sector may seem complicated. The Petroleum Safety Authority has produced an educational guide to the safety regime. An audit of the Martin Linge project was conducted by the Petroleum Safety Authority Norway (PSA) on 28–30 March 2017.
A report from Norway’s Auditor General criticizes several aspects of the way health, safety, and the environment in the Norwegian oil and gas industry is followed up by the Petroleum Safety Authority Norway. Norway has invited companies to submit bids to use subsea reservoirs to store carbon dioxide near the country’s largest oil and gas field, Troll. Statoil To Become Equinor, Dropping'Oil' To Attract Young Talent Shareholders in Norway’s largest company, Statoil, approve the board’s proposal to drop “oil” from its name as its seeks to diversify its business and attract young talent concerned about fossil fuels’ impact on climate change. But serious personal injuries are growing, while feedback on the working environment, the HSE climate and perceived risk is moving in the wrong direction. Norwegian suppliers Framo, Maritime Partner, Norbit Aptomar, and NorLense have come together to create the Oil Spill Recovery Vessel Group to offer a complete oil-spill-response solution.
Even as the Trump administration has taken steps to expand offshore oil drilling, a new report shows that thousands of oil spills are still happening and that workers in the oil and gas industry are still dying on the job. Companies in the petroleum industry, from exploration and production, to transportation, refining, and distribution, operate around the clock. This paper intends to raise awareness on the impact of fatigue in the petroleum industry and recommend a framework for fatigue risk management. This paper describes an operator’s experience with HFE during the construction and fabrication/installation phase of projects, including welding during the fabrication of buoyancy tanks, emergency preparedness, and the use of 3D model walk-throughs. In this case, a film guides the audience to make positive, personal choices whenever planning and operating a work at height. Safety depends on developing a dedicated culture mind-set and mitigation of risks, from the planning and engineering phases to the work site.
Africa (Sub-Sahara) ExxonMobil will drill its first exploratory well offshore Liberia this month, the company announced on 18 October. A deepwater well is planned on the Liberia-13 Block, which is about 50 miles off the coast of the West African country. Solo Oil plans to spud the Ntorya-2 appraisal well in Tanzania next month. The drilling pad is a mile southwest of the 2012 Ntorya-1 discovery well, which was tested at rates of 20.1 MMcf/D of gas and 139 B/D of condensate. An independent report estimated the discovery to hold 153 Bcf of gas in place, of which 70 Bcf is considered a gross best-estimate contingent resource. A gross best estimate of more than 1 Tcf of gas in place has been made for the Ntorya prospect as a whole, in which the company has a 25% interest. Asia Pacific BP has decided to abandon drilling plans in the Great Australian Bight offshore southern Australia, an area in which prospective drilling has long been contested by environmentalists.
The Martin Linge field, seen here during a utility module installation in July, is now scheduled to start up in early 2020. Equinor has revised the estimated cost for developing the Martin Linge oil and gas field in the Norwegian North Sea. The field, which the company purchased from Total late last year, is now expected to cost $5.68 billion (NOK 47 billion) to develop, up from the $4.96 billion (NOK 41 billion) estimated last year and 59% higher than the originally planned budget developed in 2012. After successful platform installation the focus is now to ensure high-quality completion of the project and safe startup of the field.” Startup for the field has also been pushed back from the first half of 2019 to the first quarter of 2020.
This paper presents and discusses the results of a series of field applications where innovative, expandable under reamer technology in combination with wired drill pipe (WDP) technology was implemented by Total E&P Norge on the Martin Linge field development project in the Norwegian sector of the North Sea.
Martin Linge's resources comprise an oil reservoir and several, deeper, structurally complex, high-pressure gas and condensate reservoirs. The oil reservoir is developed with long horizontal wells and several deviated wells will be drilled to unlock the deeper gas and condensate reserves. The field was initially discovered in 1975 but proved too complex to develop at the time.
Over the years, several exploration and appraisal wells were drilled within a narrow pressure window, with multiple BHA runs per section. The complex drilling environment posed many challenges, including severe mud losses, unstable formations (borehole collapse) and excessive downhole shock and vibrations resulting in poor MWD/LWD signal and tool failures.
The rig utilized to drill the Martin Linge field is equipped with Wired Drill Pipe (WDP) telemetry. This is a drillpipe which enables bi-directional, low-latency, high-speed data transmission. Conventional telemetry methods only provide very limited bandwidth for real-time data transmission and can suffer from signal reliability problems under adverse conditions; for example: no mud pulse data transmission during pump-off or at low flow rates, decoding issues during high levels of downhole shock and vibrations and unfavorable mud conditions.
The on-command digital, expandable under reamer is fully integrated into the bottomhole assembly (BHA) and can be monitored and controlled from the surface. The real-time feedback from the reamer includes tool vibration and stick slip (VSS) data, and confirmation of blade activation status and blade position (being fully retracted, fully extended, or transiting between the fully retracted and fully extended position). The extended blade position is pre-configured to a certain postion on surface and the reamer will open up to this position when activated, afterwhich reaming operations will begin. The real-time feedback reduces operational uncertainty during reaming and saves time for a shoulder test. Unlimited activation cycles provide the capability of selective reaming. The flexible placement of multiple reamers in the BHA enables near-bit and main reaming applications, and a combination of both. When used for near-bit reaming service, the reamer can reduce the rat-hole length to 4 m, compared to an application where it is placed 40 to 70 meters behind the bit. Significant time savings can be achieved by eliminating the dedicated rat-hole run.
The combination with WDP boosts the advantages of this innovative under reaming technology. The short activation time is reduced further compared to conventional downlink and mud-pulse telemetry, providing significant time savings. The low latency of the high-speed communication to the reamer enables on-time decisions during complex drilling and reaming applications.
This paper summarizes the resulting efficiency gains and quantified time savings achieved by the combination of innovative under reaming and WDP technologies. This combination enables wells to be drilled without the typical limitations imposed by conventional reaming and telemetry methods.
Larsen, David (Baker Hughes Inc.) | Antonov, Yuriy (Baker Hughes Inc.) | Luxey, Pascal (Baker Hughes Inc.) | Skillings, Jon (Baker Hughes Inc.) | Skaug, Mats Bjørndal (Total E&P Norge) | Wagner, Vincent (Total E&P Norge)
The Martin Linge field (originally named HILD) is a new field development in the Norwegian North Sea. The field consists of two main reservoirs, the Eocene Frigg reservoir with oil accumulation, and the Jurassic Brent reservoir with gas/condensate accumulations. The paper describes the procedures applied during geosteering operations, observations and results of the oil production wells drilled on the Martin Linge field
The Frigg reservoir consists of unconsolidated multi-darcy sandstone. For optimal production, horizontal production wells have been selected. Drilling in unconsolidated reservoirs exposes risks related to wellbore instability. Reservoir navigation has been identified as an important measure to ensure optimal wellbore placement to reduce exposure to unstable formations. The production strategy however has several constraints that limit the geosteering options: 1) The horizontal production drains needs to be accurately placed within a narrow 4 meter True Vertical Depth (TVD) window at the top of the oil rim; 2) to achieve the desired productivity, the geometry and fluid contacts of the oil accumulation require horizontal sections longer than 1000 meter Measured Depth (MD) with net sand exposure; 3) The well trajectory needs to be designed so it minimizes shale exposure within the production window for two main reasons: optimizing the drainage and reducing the risk of wellbore instabilities; 4) limit to Dog Leg Severity (DLS) so the completion running of the well remains at low risk.
To achieve the optimal placement of the oil producers within the constraints stated above, Extra Deep Azimuthal Resistivity (EDAR) (Hartmann et. al., 2013) has proven to be of great value. EDAR measures low frequencies and is thereby able to obtain a radial detection capacity that is greater than 20m (Antonsen et. al., 2015 and Larsen et. al 2015).
This paper will first describe a mathematical analysis of the wellbore trajectory made prior to drilling in order to assess the best trajectory available. This analysis takes in consideration input such as formation dips and thickness along with all the constraints mentioned above. Once the drilling plan is established, the description of the real-time geosteering activities shows how the technologies in place down hole helped keep the drilling program close to plan.
There are many physical and financial factors that determine the optimum power generation solution on an Offshore installation - space requirements, weight, reliability, and maintenance requirements to name a few. On top of these factors, environmental impacts must be considered, such as emissions of Nitrous Oxides (NOx) and Carbon Dioxide (CO2), and visible pollution like flaring.
While on ‘conventional’ offshore oil and gas fields, there is usually plentiful gas available to provide the fuel for power generation, in some instances, such as Heavy Oilfields or Gas Condensate fields, using the preferred fuels available on the platform provides additional challenges: for instance Heavy Oilfields tend to be gas deficient, with insufficient associated gas over field life to fully fuel a power plant, and so either require the import of fuel, such as diesel or Heavy Fuel Oil, or the use of the produced crude oil itself; On Gas condensate fields with low condensate quantities that make export uneconomic, the condensates themselves maybe the preferred fuel. And increasingly process heat is required, potentially requiring the combustion of additional fuel to provide the energy required.
While CO2 emissions are predominantly dependent on energy efficiency, both CO2 and NOx emissions are also fuel dependent. In addition to the ‘direct’ emissions caused by combustion of fuels to provide the energy required for Oil & Gas operations, there are also ’indirect’ emissions, such as those involved in transportation of consumable items to the platforms, and wastes produced that must be disposed of in an environmentally safe manner.
This paper looks at the types of fuels that are most commonly used for offshore power generation, the most common technologies that are considered for power generation, and the potential advantages and disadvantages of these technologies in an offshore application. It also looks at ways of reducing combustion emissions such as NOx, and using Cogeneration as a means of reducing CO2 emissions by maximising overall energy efficiency.