In the book A Journey to Sakhalin, the great Russian writer Anton Chekhov described the island, then a "katorga"--a penal colony--as a hellish place. Two centuries later, Sakhalin has changed in numerous ways and has become famous for its enormous hydrocarbon resources that lie underneath the island's shelf. Even with the considerable infrastructure investments related to oil and gas activity, Sakhalin remains a place of large contrasts: some may find it a sparsely populated island whose few cities are dominated by gloomy concrete apartment blocks and scarce roads, while others will enjoy its spectacular scenery and will keep in their memory the charming bubble of the Okhotskoye Sea. Sakhalin is the largest island in Russia. This fact alone makes locals proud, as they are the residents of the biggest island in the largest country in the world.
An operator was drilling complex big-bore gas extended-reach drilling (ERD) wells from an offshore Sakhalin Island platform. Because of the shallow gas anomaly presence beneath the platform, there was a requirement to set an intermediate casing or liner at ~375-m true vertical depth (TVD), which was between the 30-in. driven conductor at 170 to 175-m TVD and the next casing setting depth of 950 to 1065-m TVD. Due to the well complexity and completion requirements, conventional casing design with no underreaming operations was not an option.
Well reach and complexity significantly increased since the project started in 2007, which called for improvements in wellbore geometry. The wellbore geometry underwent few changes, concluding with the latest most favorable required for a 27 to 28-in. directional tophole out of a 30-in. conductor with the maximum bit size pass-through diameter of 25-in., and setting 24-in. liner at ~375-m TVD. Originally, these types of topholes were delivered in two separate trips. On the first trip, the 24-in. borehole was drilled with a mud motor bottomhole assembly (BHA), and on the second trip, underreaming-only operations were performed to obtain final borehole diameter. This operation required additional rig time and caused excessive vibrations during underreaming. A different type of underreamer was implemented successfully to eliminate vibrations, but it did not reduce the number of trips. The ultimate solution was to run the underreamer below a bent mud motor, enabling simultaneous drilling and underreaming of the directional top hole while steering the trajectory in a crowded subsurface environment. The presence of deviated conductors with 6 to 8° inclination at the shoe in all outer slots played a substantial role in overall success of the operation. It is very unlikely that the same results could be achieved if the outer slot conductors were straight.
Installing the underreamer below the mud motor worked successfully in five recent wells, saving a trip in each well. The tophole trajectory was effectively steered away from the offset wells, creating a no-collision-risk situation. A 24-in. liner was run to the planned depth and cemented. This technique was accepted by the operator for the major offshore project and used as the way forward for the remaining five outer slots.
The successful implementation of the simultaneous drilling and underreaming technique demonstrated the benefits and qualitative acceptance of using an underreamer below the mud motor for the directional tophole in this major Sakhalin offshore project. The knowledge and lessons learned from the project can be applied to other worldwide projects with identical or similar casing design requirements.
A case history from Offshore Israel is presented that describes the successful delivery of one (1) ultra-high rate gas well (+250 MMscf/D) completed in a significant (11.5 TCF) gas field with 7 in. production tubing and an Open Hole Gravel Pack (OHGP). The well described, Tamar 8, was completed approximately 4 years after the start of initial production from the Tamar development. Several operational innovations and process improvements were implemented that resulted in a significant reduction in rig time. A novel multi-purpose integrated tool string design enabled the sequential drilling of the pilot hole, underreaming of the reservoir section, several fluid displacements and casing cleaning in a single trip. The completions were installed with minimal operational issues (completion Non-Productive Time, NPT = 2.6%). Production commenced in April 2017. The initial completion productivity of this new well exceeded the five wells completed in 2012. Peak production rate to date is 281 MMscf/D.
Lu, Wenjun (NTNU & Kvaerner) | Samardzija, Ilija (NTNU) | Lubbad, Raed (NTNU) | Sukhorukov, Sergiy (Kvaerner) | Hagen, Dagfinn (Kvaerner) | Rognaas, Gunnar (Kvaerner) | Østlund, Hilde Benedikte (Kvaerner)
With a series of physical model tests performed during February to August 2016, Arctic towing operation was investigated while towing a Gravity Base Structure (GBS) in managed sea ice with varying parameters: ice concentration, floe size, towing speed and towing configuration. The CONDRILL™ Arctic driller (Gravity Base Concrete structure) is a promising structural concept for extended exploration drilling operations in limited open water season and in harsh ice conditions. In the studies, the model-scale Arctic driller concept were constructed and tested in different paraffin-made model ice conditions. The tests, designed to shed light on both the physics and the practicalities of moving the GBS in varying ice conditions where towing force and structural stability, influenced by ice resistance are central for a successful platform design. The current model test is the first in a series where the results will be used as design input as well as subsequent marine operations employed for moving the platform in managed sea ice. This paper discusses initial assessments of towing force under varying ice conditions through physically modelling the most significant ice load contributor (i.e., the ice accumulation and clearing process). Based on the model tests, an optimum towing configuration, which involves no permanent ice jamming in all the tested ice conditions, was identified. In addition, it was found that for ice concentrations lower than 60%, the towing speed (or hydrodynamics) governs the towing resistance and the influence from ice floes are minor. However, while at high ice concentration (e.g., ≥70 - 75%), we are shifting from a hydrodynamics governed scenario into multibody dynamic interaction governed scenarios, in which, ice accumulation/clearing and internal friction resistance between the ice floes dominate the tow resistance. The study highlights the importance of an efficient ice clearing mechanism to release the pressure built-up in front of the structure and transport broken ice to the wake region of the structure, which results in lower resistance during towing. The studies reported in this paper contribute to the following items: 1) The multibody dynamic based physical modelling test would be the first of its kind to isolate this important physical process and to study it thoroughly without the influence from other physical processes such as sea ice fractures. 2) The test results are useful to validate currently available numerical simulation tools based on Discrete Element Method (DEM).
An operator is delivering complex extended-reach drilling (ERD) wells from an offshore platform and experiencing up to three weeks of nonproductive time (NPT) to pull out of hole (POOH) bottomhole assembly (BHA). Multiple BHA’s have been lost in the 17 ½-in. hole section in faults, and packing-off in unstable formations. Initially the root cause was identified to be hole cleaning, in particular, in the "heel" of the section-avalanche zone-extending 400m below the 18 5/8-in. casing shoe. Cleaning an ERD high angle (>70°), large hole well is a well-known challenge. The initial solution was to reduce the hole size from 17 ½-in. to 16-in. while running the same casing string. This was done primarily to increase the annular velocity to improve hole cleaning. As we will see, as the Operator continued to analyze the problems, the root cause changed, as did the solutions, but 16-in. hole size was still the preferred hole size for the many benefits it brings. All risks associated with the change in hole size had to be understood and managed.
Solutions that were executed, included: trajectory optimization based on updated Geomechanics modelling, Extended Leak-off-tests, flat rheology drilling fluid, mud additives, cementing recipes, "fit for purpose" BHA design, Drilling/POOH/Casing running pre-job modeling and real time monitoring. All this helped to optimize the delivery of a "cemented-in-place 13 3/8-in." production casing for the most recent well in the Lunskoye gas field.
The optimized high angle 16-in. hole section was drilled from 1264m to 3806m Measured Depth (MD) (2542m length) at over 80° inclination. The 13 3/8-in. production casing was then run and cemented without any issues to the planned depth in this reduced hole size. Previously, the same size production casing was run on the project in 17 ½-in. sections. On this particular well the hole section was delivered 29 days ahead of the planned approved for expenditure (AFE) time of 55 days. Additional benefits gained by drilling a smaller hole size were savings of 67 m3 of cement and 110 m3 of drilling fluid. Two logistic boat trips were also saved due to fewer materials required. The method also increases the cuttings re-injection (CRI) capability and longevity, bringing additional long-term savings.
The successful drilling of this well shows the benefits and qualitative acceptance of downsizing the hole for this major Sakhalin offshore project. The well also provides a basis for the oil and gas industry population to consider the possibility and benefits of drilling a 16-in. extended reach hole size instead of a 17 ½-in. hole and cementing in place the 13 3/8-in. casing string.
Romanov, A. S. (Tyumen Petroleum Research Center) | Buchinsky, S. V. (Tyumen Petroleum Research Center) | Yushkov, A. Yu. (Tyumen Petroleum Research Center) | Glumov, D. N. (Tyumen Petroleum Research Center) | Voikov, G. G. (Venineft)
A case study of a gas-condensate field located on the northeastern shelf of Sakhalin Island demonstrates the possibility of development of condensate-containing gas reserves by drilling very long ERD wells (drilling from the shore). The development system described in the paper includes drilling well with upward orientation. Such design provides complete cleaning of a wellbore from fluids and solids accumulated over a long period of maintenance-free operation. The choice of a development system using horizontal wells is also associated with the geological structure of the field (massive type accumulation with a single gas-bearing contour is broken by tectonic faults into separate blocks with different hypsometric elevations). Under the technical, economical (drilling from platform and from land, the use of subsea production systems, ice gouging with hummocks), and environmental (presence of valuable fish species in water areas and permanent residence of indigenous peoples) limitations, the development of individual wells with vertical completions turned out to be unprofitable. For the first time for this type of accumulation located in a coastal zone, a unique method of monitoring the recovery of reserves within the cross-section, as well as movement of the gas-water contact without the use of monitoring and pressure observation wells was suggested.
Tistel, Joar (Norwegian University of Science and Technology) | Eiksund, Gudmund R. (Norwegian University of Science and Technology) | Hermstad, Jon (Kvaerner, Concrete Structures) | Bye, Anders (Multiconsult) | Athanasiu, Corneliu (Multiconsult)
Concrete Gravity Based Structures (GBS) have been used in the oil and gas industry since the early 1970-ties. Several structures have been installed worldwide at various water depths and soil conditions. Concrete Gravity Based Structures have proved to be well suited in harsh offshore environments. The structures have therefore been chosen as the preferred concept for several recent projects in arctic areas. GBS structures are robust and constitute a solid substructure for the topsides. The geotechnical design of the structures is based on proven principles. The concrete GBS are however relatively expensive, and in order to limit the costs it is important to optimize the design.
The first sections within this paper presents the state-of-the-art for GBS geotechnical design. Further, the paper assess a selection of design exercises which can be performed to optimize the foundation design. The examples are especially governing for structures on sands.
Healy, John (Healy Energy) | Sanford, Jack (Sanford Engineering) | Hopper, Tim (Noble Energy) | Dufrene, Kerby (Noble Energy) | Fink, Josh (Noble Energy) | Balderrama, Christian (Noble Energy) | Steve, Vickers (Baker Hughes Drilling Fluids) | Mackenzie, Grant (Baker Hughes Drilling Fluids)
A case history from Offshore Israel is presented that describes the successful delivery of five (5) ultra-high rate gas wells (+250 MMscf/D) completed in a significant (10 TCF) gas field with 7 in. production tubing and an Open-Hole Gravel Pack (OHGP). Maximizing gas off-take rates from a gas reservoir with high flow capacity (kh) requires large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of ultra-high rate gas wells was made to select and finalize the design concept after which the commensurate engineering rigor was applied. This paper will highlight the design, qualification, Quality Assurance / Quality Control (QA/QC) and operational performance of the completion fluids inclusive of the Reservoir Drill-in Fluid (RDIF) and the breaker. Completion fluids are critical to the success and production efficiency of an OHGP. The completions were installed with minimal operational issues (Average NPT ˜4%). Production commenced on March 31, 2013. All wells have performed to expectations with maximum well rates up 340 MMscf/D.
Over the past 30 years, Shell has forged a leading position as a deepwater oil and gas producer and developer. Our world-class deepwater capability is reflected by a record of more than 20 successful deep water projects, deployed globally, and a remarkable portfolio. The challenges in safely and successfully developing deepwater fields include scale, complexity and environmental extremes. Nevertheless, we are moving further offshore, into deeper waters, addressing more complicated reservoirs. We build upon our successes, incorporating the key lessons into our new mega projects and into our technology programmes, to ensure we remain a global deepwater leader.
In addition to the innovative approaches seen in deepwater oil projects, we are seeing unparalleled and exciting innovation in our industry creating new sources of supply and demand for liquefied natural gas (LNG). Shell is pioneering large-scale Floating LNG (FLNG) with the groundbreaking Prelude project. The Prelude megaproject is well underway, with construction occurring at various locations around the world. Shell FLNG will unlock additional significant reserves of already discovered gas. And we are now seeing others turning to our technology to help develop their reserves such as the Browse joint venture in Australia. FLNG projects will create jobs, tax revenues and new opportunities for both businesses and host governments.
Currently, the Arctic produces about 10% of the world’s oil and 25% of its gas, altogether some 8 million barrels of oil equivalent per day, of which the majority is produced in the Russian Arctic onshore. But the region holds substantial additional resources. The 2008 US Geological Survey estimated that the Arctic contains 13% of the world’s yetto- find oil, 30% of the world’s yet-to-find gas, and 20% of the yet-to-find natural gas liquids resources on the planet, totalling around 400 billion barrels of oil equivalents. As energy projects become more complex and technically demanding, we at Shell believe our engineering experience will be a deciding factor in Arctic energy growth and the Sakhalin-2 project, which operates amid some of the world’s harshest conditions in Russia’s far east demonstrates Shell’s ability to manage the risks and ensure safe and responsible development.
At Shell, we have no doubt that we will need to continue to push new physical and innovation frontiers in the future as we move to deeper water and increasingly remote locations, and as demand for energy around the world increases. We look forward to the challenge.