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Var Energi has confirmed a discovery at its King and Prince exploration wells in the Balder area in the Southern North Sea. Success at the combined King and Prince exploration wells lifts preliminary estimates of recoverable oil equivalents between 60 and 135 million bbl. King/Prince was drilled in PL 027 by semisubmersible rig Scarabeo 8. The Prince well encountered an oil column of about 35 m in the Triassic Skagerrak formation within good to moderate reservoir sandstones, while the King well discovered a gas column of about 30 m and a light oil column of about 55 m with some thick Paleogene sandstone. An additional King appraisal sidetrack further confirmed a 40-m gas column and an oil column of about 55 m of which about 35 m are formed by thick and massive oil-bearing sandstone with excellent reservoir quality.
The jackup-type mobile offshore drilling unit (MODU) has become the premier bottom-founded drilling unit, displacing submersibles and most platform units. The primary advantage of the jackup design is that it offers a steady and relatively motion-free platform in the drilling position and mobilizes relatively quickly and easily. Although they originally were designed to operate in very shallow water, some newer units, such as the "ultra-harsh environment" Maersk MSC C170-150 MC, are huge (Figure 1) and can be operated in 550 ft in the GOM. This type of unit can be commercially competitive only in the North Sea and in very special situations. Figure 1--Maersk's giant jackup (largest in the world) designed for deepwater use (550 ft in the GOM) and harsh North Sea environment.
Nearly 150 workers have been evacuated or are due for evacuation from Shell's Shearwater project in the North Sea since a COVID-19 outbreak emerged at the end of June, the company said on 20 July, as the industry called for an exemption from self-isolation rules for offshore workers. So far, 26 people at the Shearwater oil and gas hub have tested positive for COVID-19, with another 122 categorized as having been "close contacts" of those infected, Shell told S&P Global Platts. Most have already been flown to shore, with a small number isolating at the facility before returning to shore, Shell said, adding that the spread of infection was slowing, with only five cases detected in the last 7 days of the outbreak. Shearwater is the focus of concerns that rising UK infection rates could spread to the offshore oil and gas sector, which normally provides 1 million B/D of oil including the Brent and Forties benchmark grades and meets about half the country's gas needs. Offshore workforce numbers have recently recovered to well over 10,000, following a steep fall last year in response the pandemic, according to industry figures.
Chevron, Shell, and TotalEnergies are supporting a 12-month research project, which is expected to achieve a world-first in demonstrating high-resolution satellite-based monitoring of anthropogenic methane (CH4) emissions at sea. Led by Canadian-based GHGSat, the new research project aims to assess the feasibility of space-based methane monitoring technology to measure emissions from offshore oil and gas platforms. GHGSat is testing a technique developed by NASA, amongst others, and proven in fields such as ocean height and ice-thickness measurement. With a vantage point 500 km above the Earth, and high revisit rates, the company believes satellites could hold the key to verifying emissions from rigs, easily and cost-effectively. The study will monitor 18 offshore sites in locations such as the North Sea and the Gulf of Mexico for over 12 months.
Odfjell has been awarded a three-well, $40-million drilling contract for its semisubmersible drilling unit Deepsea Stavanger by Equinor. The rig will join sister units Deepsea Atlantic and Deepsea Aberdeen under contract with the Norwegian operator. The rig is scheduled to start drilling the first of three planned exploration wells in the North Sea in February 2022. The wells are expected to take about 4 months to complete. The contract includes continuing options after the initial phase.
Equinor has received regulatory approvals to proceed with the development of the Breidablikk field in the North Sea. The plan for development and operation for the $2.1-billion project was submitted to authorities in September. Production from the field is scheduled to start in the first half of 2024. "We are very pleased that the authorities have approved the development plans for the Breidablikk field," said Arne Sigve Nylund, Equinor's executive vice president for projects, drilling, and procurement. "The development of one of the largest undeveloped oil discoveries on the Norwegian continental shelf (NCS) will create substantial value for Norwegian society and the owners while securing high activity and jobs for many years ahead."
The Norwegian government has earmarked two areas in the North Sea to accommodate up to 4.5 GW of floating and bottom-fixed wind turbine capacity. Utsira Nord, an area of 1000 km2, is northwest of Stavanger, and Soerlige Nordsjoe II, an approximately 2,590-km2 area, borders the Danish sector of the North Sea. Utsira Nord is seen as suitable for floating wind power, while Soerlige Nordsjoe II is suitable for bottom-fixed wind power turbines. Norway, western Europe's largest oil and gas producer, is pushing ahead with North Sea wind power despite its already-plentiful renewables supply as it examines how it can adapt its petroleum industry to meet climate goals. "We have the knowledge, the experience, and a good track record from establishing and building advanced installation in tough conditions far out at sea," Reuters quoted Norwegian Oil and Gas Association director general Anniken Hauglie as saying.
Abstract This paper reviews the recently concluded successful application of a Managed Pressure Drilling (MPD) system on a High-Pressure High-Temperature (HPHT) well with Narrow Mud Weight Window (NMWW) in the UK sector in the Central North Sea. Well-A was drilled with the Constant Bottom Hole Pressure (CBHP) version of MPD with a mud weight statically underbalanced and dynamically close to formation pore pressure. Whilst drilling the 12-1/2" section of the well with statically under-balanced mud weight, to minimize the overbalance across the open hole, an influx was detected by the MPD system as a result of drilling into a pressure ramp. The MPD system allowed surface back pressure to be applied and the primary barrier of the well re-established, resulting in a minimal influx volume of 0.06 m and the ability to circulate the influx out by keeping the Stand Pipe Pressure (SPP) constant while adjusting Surface Back Pressure (SBP) through the MPD chokes in less than 4 hours with a single circulation. After reaching the 12-1/2" section TD, only ~0.025sg (175 psi) Equivalent Mud Weight (EMW) window was available to displace the well and pull out of hole (POOH) the bottom hole assembly (BHA) therefore, 3 × LCM pills of different concentrations were pumped and squeezed into the formation with SBP to enhance the NMWW to 0.035sg EMW (245 psi) deemed necessary to kill the well and retrieve BHA. MPD allowed efficient cement squeeze operations to be performed in order to cement the fractured/weak zones which sufficiently strengthened the well bore to continue drilling. A series of Dynamic Pore Pressure and Formation Integrity Tests (DPPT and DFIT) were performed to evaluate the formation strength post remedial work and to define the updated MMW. Despite the challenges, the MPD system enabled the delivery of a conventionally un-drillable well to target depth (TD) without any unplanned increase/decrease in mud weight or any costly contingency architecture operations, whilst decreasing the amount of NPT (Non Productive Time) and ILT (Invisible Lost Time) incurred. This paper discusses the planning, design, and execution of MPD operations on the Infill Well-A, the results achieved, and lessons learned that recommend using the technology both as an enabler and performance enhancer.
Clegg, Nigel (Halliburton) | Duriez, Alban (Halliburton) | Kiselev, Vladimir (Halliburton) | Sinha, Supriya (Halliburton) | Parker, Tim (Halliburton) | Jakobsen, Fredrik (Aker BP) | Jakobsen, Erik (Aker BP) | Marchant, David (Computational Geosciences Inc.) | Schwarzbach, Christoph (Computational Geosciences Inc.)
Abstract Mature fields contain wells drilled over decades, resulting in a complex distribution of cased hole from active producers, injectors, and abandoned wells. Continued field development requires access to bypassed pay and the drilling of new wells that must be threaded between the existing subterranean infrastructure. It is therefore important to know the position of any offset wells relative to a well being drilled so collision can be avoided. A well’s position is determined by directional survey points, for which the measurement error accumulates along the length of the well, increasing the uncertainty associated with the well position. The positional uncertainty is greater in wells drilled with older generations of surveying tools. Thus, a new well may be required to enter the ellipse of uncertainty representing the potential position of an older well, risking collision, to be able to reach desired targets in more distal parts of the reservoir. A potential solution to reduce collision risks is ultra-deep electromagnetic (EM) logging-while-drilling (LWD) tools, whose measurements are strongly influenced by proximity to metal casing and liners. This paper presents 3D inversion results of ultra-deep EM data from a development well in a mature field, which were used to identify a nearby cased well. Due to the large effect of casing on the measured EM field, it is important to validate the 3D results; this has been achieved using a synthetic modelling approach and assessment of azimuthal EM measurements. Models were created with casing positioned within resistive media with similar properties to those seen in the studied cases. Inverting these models allows testing of the inversion algorithm to show that it is providing a good representation of the cased well’s position relative to the newly drilled well. Further analysis of recorded and synthetic data showed that the raw EM field is strongly influenced as the casing is approached. The casing can be seen to clearly affect the EM field measurements when it is in the region of 10 to 15 m ahead of the EM transmitter, with the effect increasing in magnitude as this distance diminishes. Modelling shows that the EM field measurements behave in a predictable manner. As the ultra-deep EM tool approaches a cased well, it is possible to determine whether the casing is above, below, or critically, directly in line with the planned trajectory of the new well. Existing subterranean infrastructure can pose a major hazard to the drilling of new wells. Being able to identify an old well ahead of the bit using ultra-deep EM measurements would allow a new well to be steered away from the hazard or drilling stopped, preventing a collision. In addition, this may also allow the drilling of well paths that would otherwise be impossible to drill, due to the limitations imposed by positional uncertainty of the new and offset wells. This use of ultra-deep resistivity technology takes it beyond its more traditional benefits in well placement and formation evaluation, making it useful for improving well drilling safety.
Abstract The evaluation of downhole fluid analysis (DFA) measurements of asphaltene gradients provides the ability to determine the extent of asphaltene equilibrium and the operative reservoir fluid geodynamics (RFG) processes. Typically, equilibrium of reservoir fluids indicates reservoir connectivity, a primary concern in field development planning. Currently, the modeling of asphaltene gradients is done through the manual evaluation of the DFA optical density gradients. The optical density measurements are fit to an equation of state (EOS), such as the Flory-Huggins-Zuo EOS, and evidence for asphaltene equilibrium is concluded if the inferred asphaltene diameter corresponds to that of the Yen-Mullins model for asphaltene composition. In this work, we present an automated Bayesian algorithm that proposes multiple hypotheses for the state of asphaltene equilibrium. The proposed hypotheses honor DFA measurements; physical models for asphaltenes in equilibrium, such as the Yen-Mullins model; and prior domain knowledge of the reservoir, such as geological layers, faults, and flow units. The leading hypotheses are reported, and evidence for or against asphaltene equilibrium is concluded from inferred quantities. Our proposed method provides a faster way for domain experts to explore different reservoir realizations that honor the theory of asphaltenes gradients and previous knowledge about the reservoir. We verify our novel method on three case studies that are undergoing different RFG processes through comparison of the interpretation done by domain experts. While there are many reservoir complexities associated with each case study, we focus on whether the underlying RFG process corresponds to the asphaltenes in equilibrium. The first case study is a light oil reservoir in the Norwegian North Sea that is mostly in fluid equilibrium with exceptions at the flanks. The second case study is a black oil reservoir that has undergone a fault block migration after the reservoir fluids had a chance to achieve equilibrium. The last case study is a black oil reservoir in quasi-equilibrium due to biodegradation in the lower portion of the well.