This paper provides the results of the application of integrated approach to drill the longest extended reach well which has ever been drilled in Odoptu-more field (North Dome) in Sakhalin. Although many extended reach drilling (ERD) wells have been already drilled by the operator in Odoptu-more field, extreme reach wells always require new solutions. Reaching remote reservoirs by applying standard well design of Odoptu-more field was not possible due to high standpipe pressure (SPP) and equivalent circulating density (ECD) in 8 ½-in production section. Engineering study resulted in partial upsize of a well design and change 9 5/8-in casing to liner followed by remaining challenges: 9 5/8-in liner could not be delivered to required depth due to string buckling. Several key technical solutions were implemented in the project thus allowing to deliver the longest well accident-free. Those solutions included well design modification allowing to drill 8 ½-in production section to reach remote reservoirs and 9 5/8-in liner delivery to the required depth using "mud over air" flotation technique for the first time in the project. Having applied integrated approach, the project team broke a new record in drilling the longest well at Odoptu-more field with total measured depth 8699m, ERD ratio 4.89 and Directional Difficulty Index (DDI) of 7.6 ( Alistair W. Oag 2000 ). Drilling extreme reach ERD well unlocked opportunities for the operator to reach and put into the production more distant offshore oil-bearing reservoirs from the land rig without changing existing pad facilities.

This report represents the findings of a survey of managers and specialists of state and private enterprises from oil and gas sector of the Russian Federation. The survey findings reflect technological needs of the industry, plans for technological development of the enterprises in the short-, medium- and long-term periods as well as the readiness of enterprises for technological cooperation.

The paper describes the main approaches used in the development of predictive analytics algorithms, both of a general nature and in the field of well drilling. When describing the algorithms used, the basic assumptions of each and the ensuing limitations of the developed model are explained. The necessity of building hybrid models, involving the full amount of information collected, including calculations carried out during the construction of the well, both from the engineering and geological sides, is shown. The paper discusses the culture of working with data in the oil and gas field in general and in particular well drilling. The current level does not allow companies to create scalable solutions of predictive analysis. As a result of the work done, the basic rules were proposed, the first step was taken towards standardizing the process of collecting and analyzing information flow arising during the construction of wells.

This paper describes the results of efficient cooperation between the Operator, the General Drilling Contractor and the Service Company, who participated in the construction of horizontal wells in Yuzhno-Tambeyskoye gas condensate field. This document describes an integrated engineering approach to selection of new technical and technological solutions, which safely achieved all the geological tasks while constructing the wells. The key innovations of real-time data transmission from downhole tools, allowed the quality of the information received to be improved which increased the average rate of penetration (ROP) and reduced the well drilling time. Furthermore, during the project execution a multidisciplinary group of experts developed and successfully implemented a set of measures aimed at reducing flat time. Comprehensive planning, an efficient organizational structure, effective communication between all the participants and the introduction of new technologies resulted in the safe and successful construction of 6 horizontal wells with 1500 m long horizontal sections delivered 10% ahead of schedule. Along with the technological progress, it is important to note that during well construction a high level of HSE was achieved with no accidents occurring throughout the entire project.

The investigations, conducted by many companies, show that a long gauge PDC bits, which are used during operations with "point-the-bit" Rotary Steerable Systems (RSS), allows for mitigating the bit vibrations and improve steerability. But in this paper, we shall present the usage of the short gauge PDC bits when drilling with this type of RSS in a pay zone, which is characterized by hard streaks. More tight shaled-out interlayers were encountered in pay zone when developing a peripherical part of Verkhnechonskoye field. On the boundary of the rocks of different hardness a number of formation "pushes" (short intervals with a sharp change of the inclination) increased significantly. A continuous operation in the formation "push" intervals resulted in downhole equipment damages. When conducting kick-off operations in an open hole in multilateral wells with the use of "point-the-bit" RSS and the long gauge bits a quantity of failures reached 60 %. For that reason, it was necessary to kick off using a BHA with a downhole motor; but in this case additional runs are required. A hypothesis was made that the usage of short gauge PDC bits will help to promptly correct the wellbore trajectory when formation "push" occurs, as well as allow for drilling a few laterals over one run. Deviation from the standard design made it possible to reduce a number of runs when drilling multilateral wells, increase an average rate of penetration and significantly reduce frequency of Dogleg Severity exceedance events when passing through hard streaks.

The history of drilling for oil in the Republic of Belarus began in the mid-1960s ( Sosnok A. 2016 ), when the first industrial oil inflows were received in the Rechitsky district of the Gomel region, from wells No. 6 and No. 8. In the years that followed, local and international experience was leveraged to actively drill and develop the region’s oil deposits, using advanced technologies suited to the complex geological conditions of the Pripyat trough. The new century is calling for innovative approaches to solve well construction problems currently facing Belorusneft Production Association (PA). The need to improve drilling, completions, and production methods has led to the introduction of modern technology, with sweeping changes in all aspects of well construction. In 2019, exploration and production drilling in Belarus entered a new stage of development, in which reducing well construction time via the use of new, improved technologies became one of the highest priorities. A few decades ago, due to the complex geological structure that characterized Belarus deposits, drilling was carried out mainly by the rotary-turbine method. This method used roller cone and impregnated bits, which demonstrated quite good results; however, they did not compare to the performance of modern-day polycrystalline diamond compact (PDC) bits. In line with Belorusneft’s phased rig fleet refurbishment around 2016, PDC drill bits were introduced and deployed across all of the operator’s oilfields to handle "aggressive" hydraulic parameters in the Pripyat oil and gas basin. At the same time, there was a gradual transition from use of the turbine drilling and rotary bottom hole assembly (BHA) to BHAs that include a hydraulic positive displacement motor (PDM) and rotary steerable system (RSS). The volume of drilling with the newly configured BHA increased from 14 percent in 2016 to 83 percent by the end of 2019 Distribution of drilling volumes for Belorusneft, by year, by drive type. The increase of PDC bit usage was one of several factors that helped raise the run length per bit and the rate of penetration (ROP) to a new level. As shown in Table 2, due to the introduction of modern drilling technologies, the average ROP increased by more than 2 times since 2016, and amounted to 7.64 m/hr in 2019. With this higher ROP, it was possible to increase the total volume of drilling in 2019 by more than 1.5 times compared to 2016, without increasing the total number of drilling rigs. Average ROP and total drilling volumes for Belorusneft, by year. This paper describes the main challenges encountered in Belarus when drilling with Halliburton PDC bits, and the solutions delivered by the evolving bit design improvements. It includes the introduction of combined rock failure action bits with a higher penetration rate and, accordingly, associated cost savings. The paper also reveals the advantages of using these new bits when drilling wells in the complex geological conditions of the Pripyat sag basin. The Republic of Belarus is one of the first countries in the Eastern hemisphere to test and confirm the high efficiency of innovative bit design for drilling intercalating heterogeneous rocks of wells with different profiles, compared to ordinary PDC bits of conventional design.

Terrigenous intervals usually consist of interbedded sandstone, siltstone, clay and claystone. These intervals can be also difficult to drill even though rocks have low strength. Sticky and plastic rocks are the cause of rate of penetration (ROP) decreasing without drill bit cutting structure wear. A new hyperbolic diamond element (HDE) bit has been developed to improve drilling efficiency in such conditions. HDE has a standard cylindrical carbide substrate as conventional PDC cutter. The main difference is shape of diamond layer, it has hyperbolic profile. HDE has positive rake which helps to improve performance in soft formations: the cutter penetrates deeper in rock under the same loadings. Hyperbolic diamond element also helps to avoid ribbons generation while drilling in soft and plastic formations. HDE technology was implemented on different oilfields in Russia. Naulskoe oilfield is one of them. It is in the Timano-Pechora oil basin. Development section interval consists of terrigenous rocks: sandstone, clay and claystone. New bit design with HDE cutters was specially developed for oilfield geology. The same well profile, bottom hole assembly (BHA) and drilling parameters (flow rate, weight on bit and drill pipe rotation) were used in bit tests. HDE bits set a new field ROP record which is 70% higher than average result on the drilling pad and 17% higher than the best previous result. This achievement proved HDE technology efficient. HDE bits were used also on another oilfield which is located in the South part of Russia. Low rate of penetration is observed while drilling soft and plastic clay there even with no bit dull. There were several different tries to optimize drilling process with no success. It was decided to test hyperbolic elements technology on the oilfield. Average ROP increased in 90% as a result after HDE bit implementation. It allowed to reduce well construction time.

This article provides the results of the first experience of running a wear resistant "push-the-bit" RSS (rotary-steerable system) for kicking-off at shallow depth in poorly consolidated sand formations. According to the contractor's best practices, a shallow kick-off in sections with large diameters is performed using PDM (positive displacement motors) with a bent housing angle set up to at least 1.83 degrees. However, for wells in Odoptu field, which is located in the north of Sakhalin island, several specific features pose issues for the effective application of conventional directional drilling equipment to reach the geological targets. A standard approach for drilling the 17 ½-in. section in Odoptu wells requires two runs: Run1: A PDM with roller-cone bit are used to build the inclination from zero to 70-degrees in poorly consolidated sand formations Run2: A conventional RSS with PDC (polycrystalline diamond composite) bit are used for drilling the tangent section. The project team was challenged to reduce the well construction time by drilling this section in one run, however, there were technical concerns. Drilling with a PDM and roller-cone bit would not provide a high penetration rate in tangent section. Drilling with a conventional push-the-bit RSS might not provide the necessary DLS (dogleg severity) in the sandstone due to formation washouts. In addition, drilling in the sands exposes the drilling equipment to excessive erosion because of the high sand content in the drilling mud. Considering the average section length of 2000 to 3000 m of MD (measured depth), this wear could lead to damaging the costly drilling equipment breakdown and causing unplanned tripping operations. The project team alongside the field operator decided to test a wear-resistant RSS for one typical well of the Odoptu-Sea field. As a result, the section was drilled in one run, achieving the planned DLS without any equipment erosive wear. In addition, the 17 ½-in. section of this well recorded the highest penetration rate of 58 m/h in the field. The implementation of a wear-resistant RSS saved 6 days of the total section time.

Construction wells on the Achimov deposits was accompanied by many problems: the danger of sticking and oil, gas and water inflow; a serious decrease in the mechanical ROP on dense layers; severe downhole conditions: vibrations on dense interlayers, temperature up to 110°C, drilling mud based on diesel fuel. All of the above issues increased the number of trips due to equipment failures, increased non-productive time and, as a result, increased the well construction period. The integrated approach described in this work has significantly reduced non-productive and well construction time. The customer was suggested: – Limitation the mechanical rate of penetration (ROP) by 15m/h to control equivalent circulating density; – Control of the equivalent circulation density by the MWD sensor; – Combination of a modular motor with rotary steerable (RSS) system in bottom hole assembly (BHA) to increase the mechanical ROP during drilling in dense layers of the productive horizon; – Optimization of the bit design, taking into account geological features, meanwhile drilling with a rotary-steerable system; – Use of a new generation rotary- steerable system; – Optimization of the BHA; – Modernization of equipment preparation procedures. An integrated approach to drilling wells on the Achimov deposits with new methods and technologies offered to the customer allowed reducing the number of failures by 100-200%, which reduced the number of runs, and as a result, the non-productive time decreased. The reduction in the number of runs allowed taking from 500 − 600 meters to 1200 − 1500 meters per run. Optimization of the bottom hole assembly, including a new bit design in Russian Federation, integration of a new generation of rotary-steerable system with a modular motor, made possible to expand the boundaries of drilling modes, accordingly increase the mechanical rate of penetration. In addition, the adopted methods and technologies allowed reducing the negative impact of vibrations that occur during the drilling of dense layers. Application of the integrated approach to solve the problems, which took place during the construction of wells on the Achimov deposits, has significantly reduced: the number of equipment failures, non-productive time. Meanwhile increased the mechanical rate of penetration and drilled distance in one trip, which in general has significantly reduced the time of well construction.

The traditional considerations and guidelines regarding well planning were not applicable to the challenges that extended reach well #101 of the Uzen field have presented. On the one hand, the reservoir itself was shallow, highly heterogeneous and structurally complex. On the other hand, the well trajectory involved the long interval placed nearly parallel to the bedding of catastrophically unstable shales. The importance of geomechanical study and mud weight optimization have become very clear after reaching TD of 295.3mm section. There were no signs of instability while drilling, however the pulling out of hole was impossible without rotation, the overpulls, torque and pressure spikes resulted in fracturing the well and circulation loss, the well conditions imposed the high risk of BHA LIH. The mud was gradually weighted up from 1.15 sg to 1.40 sg according to geomechanical calculations performed in a short time. After having conditioned the mud and performed several circulation cycles the drilling string was safely extracted out of hole. Due to the highly unstable hole conditions, the decision was to sidetrack the new borehole. The main adjustment of the new trajectory of well #101 was dropping as much as possible the inclination angle when drilling through shales, at the same time allowing the maximum distance to water-oil contact. The PDM was planned to be used in the interval with high dogleg while where extended intervals of well trajectory went subparallel to bedding, the RSS was preferred, as there was a high need for lower vibrations and better cleaning quality. The morning meetings included the reports and discussion of all the involved parties: Volga Gas management, mud and drilling engineers, geomechanicists, mud loggers and geologists. The thorough inter-disciplinary analysis was performed before making any decision: routine (time and number of reaming after drilling the stand, tripping speeds, circulation timing and duration) and strategic (trajectory change, geostopping, place to perform sidetrack, completion optimization, etc) too. The holistic approach of risks’ assessment and the proactive management resulted in drilling success of the first horizontal well in the field (2480m MD, 717m TVDSS). It was drilled safely and efficiently, allowing to access the reserves, delay the onset of water production, accelerate time to reach planned production level, and increase cumulative production of oil. The success of the drilling performance was publicly acknowledged by Volga Gas.

This paper presents an efficient application of Passive Magnetic Ranging (PMR) on the B3 well sidetrack drilled on the High Pressure/High Temperature (HP/HT) Elgin field in the UK Central-North Sea. The planning and execution of this sidetrack presented an escalated set of challenges beyond those encountered in standard well conditions due to the high temperature (HT), the potential for magnetic interference and collision avoidance constraints. The PMR method was deployed in order to mitigate the risk of, and ultimately resolve, magnetic interference. This resulted in minimised collision risk and safe achievement of the sidetrack in a HT environment. Challenges were faced in the 12 ½″ section which resulted in the open-hole being plugged and abandoned below the 14″ casing shoe, with the drill-string cemented in place. A complex sidetrack was planned below the 14″ shoe. Reservoir target and collision avoidance constraints required the planned sidetrack well-path to be close to the abandoned branch, therefore magnetic interference was possible. PMR was planned in the case of interference. The aim was to make the preparation and operational deployment process as efficient as possible, while drilling this sensitive section. A work-flow was developed to manage the performance of ranging passes, specifically interfaces between all parties involved in operations. PMR was deployed to map the relative position of the well during periods of interference and develop ‘synthetic surveys’ to construct the well-path, allowing collision avoidance calculations by defining reliable projection ahead and thus permitting steering of the drilling assembly. The PMR process was successfully deployed on B3 after experiencing high magnetic interference allowing drilling to continue to planned depth with limited impact on operations. This paper provides information on the application of independent PMR and processing aspects to be considered when defining relative wellbore position based on synthetic surveys. Understanding advantages and limitations of PMR opens up opportunities to benefit from this technique in similar challenging drilling applications and help to reduce operational risk and optimise cost. PMR can thus provide a viable alternative to Gyro While Drilling (GWD), where conditions do not allow or where the probability of magnetic interference is marginal and high tool costs could be incurred when potentially not required.

This document describes the integrated engineering approach and technical solution used to perform a construction project of the first wildcat well in Khatanga subsoil area of the Laptev Sea. Because of the small scope of performed geological exploration works and the absence of any previously drilled wells within the target area, a low degree of geological knowledge existed for this project. The unique location of the license area eventually complicated the profile of the Centralno-Olginskaya 1PO wildcat well and the logistics on the peninsula, consequently affecting the planning and performance of the project. In these conditions, RN-Shelf-Arktika OOO and Halliburton encountered a range of challenging tasks associated with high quality planning and safe performance of the expected work scope within the planned timeframes. Other challenges encountered included fulfilling all geological tasks required to reduce expenses and developing technological and organization solutions for the subsequent construction of wells and the discovery of a new oilfield in the Eastern Arctic. Because of the low level of geological knowledge about the territory, the operator regularly assigned new geological tasks. These changes eventually resulted in a longer wellbore (5530 m, rather than 4200 m), increased scope of geological activities (a longer coring interval of 156 m, rather than 90 m), and well design changes (five casing strings, rather than four). To ensure the fulfillment of the required tasks, the completion of the project was based on an integrated approach for the integrity of the proposed technological and organization solutions, high quality of planning, and risk management and application of advanced technologies. This approach ensured 100% fulfillment of the geological objectives within the established timeframes and helped to develop a map of lessons learned with recommendations to optimize time and costs in the construction of future wells at the new field. Because of the project remoteness and challenging climate conditions, the well construction cost is the key factor for efficient field development ( Lebedeva et al. 2017 ).

Lost circulation is one of the main causes of nonproductive time during drilling in Eastern Siberia. In Srednebotuobinskoe oilfield major challenges are related to severely fractured igneous rock intrusion. Drilling through this interval is associated with constant severe to total losses. As a result, drilling velocity may drop below one meter per hour. Significant reduction of drilling time was achieved with application of an innovative fiber based LCM. Current paper describes results of this project. Curing losses in severely fractured igneous rock formations is challenging. In most cases the fracture width is not known; it can only be predicted. However, this prediction is not always accurate. An engineered fiber-based kill fluid was used to mitigate this lack of knowledge. Laboratory tests demonstrated ability to plug 1-5 mm fractures. System was applied in two wells in Srednebotuobinskoe oilfield. Fiber based pill was used in a combination with conventional LCMs. Additional operation time reduction was achieved by BHA compatibility. Average velocity of drilling through igneous rock interval was further compared to offset well from the same pad. Drilling through 140 meters igneous rock interval of the well took around 147 hours. Conventional LCM are sensitive to fracture width. Due to geological complexity of the interval they had limited efficiency. A novel LCM based on soft, short fibers allowed to overcome this problem. It has a dual plugging mechanism. It can bridge across fractures up to 5 mm and form a filtercake on the formation surface, mitigating losses to the fractures network. Applying this innovative solution in the 225 meters igneous rock interval of the second well (same pad) allowed to reduce drilling time to 119 hours. Thus, drilling became two times faster. Fiber based pill is also compatible with BHA, including telemetry. So additional time was saved on POOH/RIH operations. For the third well on the same pad pill placement strategy was further optimized. So, 135 meters igneous rock interval was completed in 23.5 hours. Drilling became 6 times faster comparing to the first well. Fiber based LCM showed high efficiency for mitigating severe losses in igneous rock intervals of Srednebotuobinskoe oilfield. BHA compatibility allowed to avoid additional POOH/RIH operations, providing extra value. Application of fiber based LCM led to significant acceleration of drilling igneous rock intervals. The pill was prepared on the well site with equipment available. Compatibility with surface and downhole equipment was also confirmed. Various successful field applications of fiber-based pills have been reported from various parts of the world. Current work presents first application of an engineered fiber based pill in Srednebotuobinskoe oilfield, Russia. The pill was pumped successfully in 2 wells in igneous rock intervals. Pill was placed through BHA. This solution allowed operator to achieve 6 times reduction of time required to complete the interval.

Drilling multilateral (fishbone) wells in western Siberia is a common practice. A particular characteristic of these wells is the kickoff in the openhole horizontal section—no cement plug or whipstock is used. In the overwhelming majority of wells, it is economically impractical to perform tripping procedures twice—to change the bottomhole assembly (BHA) for the kickoff, and change it again for subsequent drilling. To reduce the well construction time, one requirement is to drill the horizontal section in one run. Many operators have realized the advantages of using rotary steerable systems (RSS) for drilling multilateral wells that are becoming more complicated. During a well startup, the use of RSS to drill fishbone wells caused some concern about kickoff procedures. The operator had no experience with the process due to the analogue of adjustable kick-off sub (AKO) on the positive displacement motor PDM absence. The first kickoffs were made and resulted in a significant time increase compared to the same process with (PDM): 26 to 28 hours instead of 16 to 20 hours. Further experience with using kickoffs with RSS resulted in procedures and process improvements. Based on the experience gained, a new kickoff procedure with RSS was tested at more than 20 jobsites in Western Siberia. A notable record was achieved on one of the multilateral wells on March 18, 2018 at the job for Lukoil-Zapadnaya Sibir Ltd. The kickoff in the open horizontal section was made in 1 hour 40 minutes, whereas the standard procedure took 20 hours 30 minutes. The time reduction of the kickoff process was 92% compared to the standard procedure, and 17% compared to the previous set record. The next stage of this technology will be its application in Eastern Siberia, with some modifications based on the lithostratigraphic section of the target horizon.

This paper describes the implementation of pressurized mud cap drilling (PMCD) technology, a variant of Managed Pressure Drilling (MPD), a successful technique frequently used on oil and gas fields in Kazakhstan. It also considers the planning phase, operational aspects, and results of drilling with the PMCD technique through challenging formations. PMCD technology with a rotating control device (RCD) is a form of blind drilling, where the drilling fluid and formation cuttings are not transported to the surface. It is a non-conventional drilling technique designed to maintain annular wellbore pressure to prevent total loss of circulation. A sacrificial fluid (SAC) is injected through the drill string and light annular fluid is pumped down from the annulus to maintain borehole fill and prevent annular gas migration. Wells in this field have encountered uncontrollable losses while drilling sections of the fractured carbonate. As a result, the application of PMCD technology to meet those challenges was an obvious choice in order to achieve target depth. Conventionally drilling of the 8-in. section resulted in fluid losses of more than 450 m 3 . Consequently, passing through these challenging zones the rig crew switched from conventional drilling to PMCD. The wells were then successfully drilled using the PMCD method, without any issues or well-control incidents, and planned TD was attained. By enabling the client to reach TD, Weatherford PMCD equipment transformed a previously undrillable well into a potentially valuable asset. This operation demonstrated that PMCD can be a viable drilling technique for future wells in the field. PMCD technologies included reduced consumption of lost-circulation material (LCM) and reduced loss of mud to the formation, keeping the wells economically viable. The main objectives of these wells were to drill safely and efficiently to target depth (TD), to deliver the wells for production on schedule, reduce non-productive time (NPT), minimize the drilling risks and hazards, and optimize the drilling program.

The application of classical field development systems in the modern world is becoming more and more complicated. The global portfolio of oil and gas fields virtually ran short of reservoirs located in favorable conditions for geologists and drilling & completion engineers. New fields are either located in adverse climatic conditions (e.g., Arctic projects) or are faced with various problems related to unconventional reservoirs, complex geological structure, high pressures and temperatures. One of those problems, which has become a particularly pressing issue in recent years, is the problem of incompatibility of borehole pressures, which causes complications in the well construction: borehole wall collapses, fluid losses and sticking of drilling tools. For the well construction process this means an increased non-productive time (NPT) and extra costs. One of the solutions to such challenges is a liner drilling technology, which is actively used as a means to lower NPT and operational risks. Liner drilling systems, including those for directional drilling, are available, but for strings 178 mm (7″) and more in diameter. Smaller diameter liner drilling is carried out using directionally-uncontrollable systems, which restricts the application of the technology. In this regard the authors are offering the technology of directional drilling with a 127 mm (5″) liner, which would reduce the rig time and address the above technical problems. The task is completed by the use of a disposable bottom-hole directional assembly - a drilling bit and a bent-housing positive displacement motor (PDM with adjustable bent sub) and a retrievable telemetry system. The coil tubing (CT) can be used to extract the retrievable telemetry system. All the system elements are available on the market, the article describes the calculation results that demonstrate the possibility of the use of such a system in drilling of deep directional and horizontal wells.

On the basis of the study on drill string vibration rules in vertical well drilling and the idea of transformation of drill string vibration energy to drilling fluid hydraulic energy, a novel tool, down-hole drill string absorption & hydraulic supercharging device (DSAHSD), is designed to further improve the rate of penetration (ROP). The DSAHSD combines the advantages of reducing the axial vibration of the drill string and generating more than 120 MPa ultra-high pressure jet to effectively assist rock breaking. When the drilling fluid flows through this tool, part of the drilling fluid will be modulated to the ultra-high pressure jet by periodic compression of piston drove by drill string vibration. During this process, the ultra-high pressure jet ejected through ultra-high pressure nozzle that fixed on the bit edge in bottom hole. Because of hydraulic auxiliary rock breaking of the ultra-high pressure jet, the ROP will be improved. This tool has been applied to more than 40 wells in four oil fields throughout China. The results show that the maximum density of the test drilling fluid is 1.9g/cm3, the maximum footage is 1480m, and the operation time of the tool is more than 200 hours. Furthermore, the average ROP was increased by approximately 11% to 831%. In conclusion, the DSAHSD has the characteristics of a simple structure, has a long lifetime, is able to adapt well with existing drilling equipment, and can provide a safe and efficient drilling technique for deep wells. In addition, a novel design idea of down-hole hydraulic booster was proposed, so this is a major breakthrough of down-hole supercharging technique.

Lukoil Overseas has been partnering in deep water exploration campaigns since 2010. First operated deep water well was drilled in mid-2013. This well was drilled offshore Sierra Leone. Four other Lukoil operated wells were drilled successfully in Ghana and Ivory Coast after that. Lukoil utilized Ocean Rig's Eirik Raude and Transocean's GSF Jack Ryan for this multi-well campaign in West Africa. This project was managed by experienced Lukoil Overseas Offshore team based out of Houston. At the beginning of 2014, Lukoil Overseas executive team made a decision to drill three wells offshore Romania. These wells were planned in two offshore blocks, Rapsodia and Trident. Transocean's GSF Development Driller II was contracted in early part of 2014 for this multi-well campaign. Mobilization from US GOM to Romania Black Sea in a short duration was extremely challenging. The rig needed to pass under two suspension bridges in Turkey's Bosporus Strait. It would be necessary to remove top of the dual-activity-derrick to pass the rig under the two suspension bridges. Major engineering design work and manufacturing of equipment was required. Derrick re-installation and commissioning of all the drilling equipment was planned in Constanta, Romania. Winterization of the rig was also needed to successfully operate in the harsh weather conditions of Romania. Derrick removal and rig winterization were planned at the same time to save critical path time. The whole project took over 300,000 man-hours. On June 10 th 2014 the rig arrived in Palermo to start derrick removal and winterization. On September 6 th 2014 the rig arrived in Bosporus Strait to go under the bridges. Rig sailed to Constanta where the final re-installation of the derrick took place. Rig mobilized to location on October 31 st 2014. Well was successfully spud on November 4 th 2014. This complex project showed the experience and flexibility of both Lukoil and Transocean teams. This paper discusses the unique technologies Russian O&G Operators use to seek new exploration opportunities in harsh environments.

Bent-housing positive displacement motors (PDM) keep the leading position among tools for drilling directional wells. The efficiency of drilling deviated wells can be greatly enhanced by the method of Targeted Bit Speed (TBS). This method enables well deviation with the continuous drillstring rotation by means of amplitude modulation of PDM's rpm, which is provided by controlling the fluid flow oscillations in its working chamber. In those cases when the required dog-leg severity cannot be achieved with TBS technology, the system's operation can be suspended without retrieving the BHA to the surface with further directional drilling by conventional PDM orientation method. In order to control and direct a well trajectory in an efficient manner, it is essential to be able to assess effect of the system parameters on deviation. The paper proposes a numerical model of a BHA equipped by TBS. The model is based on the universal 3-D dynamic drillstring-in-hole model DYNTUB, which has been previously developed by the authors. For implementing TBS technology the latter model has been refined to integrate the modulation of motor rpm with the specified amplitude setting the rate of inclination angle increase/decrease and with the phase determining horizontal angle. The deflection increment of the drilling vector against the previous position is determined by averaging the inclination and horizontal angles in one revolution of the drillstring. The model accounts for the dependence between the ROP and the bit rpm composed of constant drillstring rpm and PDM rpm, which value is subject to periodic changes during rotation. The developed program was used to analyze the build-up rate of wells drilled by TBS and oriented assembly. The analysis covered straight wellbores with different orientation in the initial state (vertical and horizontal), various types of near-bit section to kink, as well as the effect of the PDM rpm modulation amplitude and the lateral bit milling capacity. Despite of the fact that in most instances the build-up rate with TBS was slightly lower than when drilling with an oriented assembly, this was compensated by a far more valuable advantage of a significant reduction in drag force during drillstring rotation. Examples of calculating the drilling directional control of S-shaped well sections at Vostochno-Urengoysky area in Yamalo-Nenets Autonomous District drilled by the TBS method and their comparison with the planned and actual trajectories are presented. The ways to improve the efficiency of well drilling by the TBS method are provided.

Pneumatic conveying is a material transportation process used on nearly every offshore rig, in which bulk particulate materials are moved over horizontal and vertical distances within a piping system with the help of an air stream. Using either positive or negative pressure of air or other gases, the material to be transported is forced through pipes and finally separated from the carrier gas and deposited at the desired destination. This mode of bulk solid transportation is efficient compared to other modes of transportation because of the flexibility of installation and application on the rigs. Although pneumatic conveying has seen increased use on drilling rigs, there are still many major problems hampering its employment in a wider range of conveying applications like high energy consumption, excessive product degradation and system erosion, unstable plugging phenomena, severe pipe vibration and repeated blockages. Further, the lack of simple procedures for the selection of an optimal system, thus use of sub-optimal system are major problems in pneumatic transport system design and rig applications. This paper presents a scientific investigation aiming to design and optimise offshore bulk transfer systems for handling of weighting materials like barite, clay type materials like bentonite and oil well cements. The approach is based on a scaling-up technique involved with pilot scale testing. Test procedures, relevant theories on gas-solid two phase flow in pneumatic transfer and results are presented in the paper. Finally, a detailed procedure on how to optimise bulk transfer on drilling rigs is presented.