Africa (Sub-Sahara) Eni started production from the Nené Marine field, which sits in the Marine XII block in 28 m of water, 17 km offshore the Republic of the Congo. The first phase of the field produces from the Djeno pre-salt formation, 2.5 km below the ocean floor at a rate of 7,500 BOEPD. Future development will take place in several stages and will involve the installation of more production platforms and the drilling of at least 30 wells. Eni (65%) is the operator with partners New Age (25%), and Société Nationale des Pétroles du Congo (10%). The well's primary target is the Bunian structure: a four-way, fault-bounded anticline, which was defined by a 3D seismic survey. It will be drilled to a total depth of 1682 m.
Africa (Sub-Sahara) Shell's new natural gas discoveries in Egypt are estimated in initial quantities at about 500 Bcf with more reserves possible, said Aidan Murphy, chairman and managing director of Shell Egypt. The discoveries, in a concession area of north Alam El-Shawish in the country's western desert, could yield 10% to 15% of the total production of Badr el-Din Petroleum Company, the 50/50 joint venture of Shell and Egyptian General Petroleum Corporation that is expected to manage the operations. Eni reported that the Laarich East-1 oil well in Tunisia has a delivery capacity of approximately 2,000 B/D. Spudded in June, the well discovered hydrocarbons in Silurian and Ordovician sandstones while reaching a final depth of 13,487 ft. The well has now been connected to production. The company continues to drill Tunisian exploration prospects that have been identified on 3D seismic surveys.
Drilling ultra-extended-reach (ultra-ERD) wellbores has redefined industry standards. Operators and service companies must fully assess the accompanying risks to maximize the overall productivity of an asset. New drilling technologies, such as improved drilling fluid design and geomechanics analyses, allow wellbores to be drilled to the lateral displacement of greater than 13 km. This requires improved absolute wellbore positioning, in conjunction with reduced uncertainties. When developing these drilling technologies, the economics must be considered so as not to exponentially increase the cost per barrel of oil. The increase in infill drilling of nearby offset wellbores requires developing improved methods that reduce wellbore position uncertainty when placing the wellbore in the reservoir, in addition to avoiding collisions.
The proposed geomagnetic referencing technique is suitable for the application to the Sakhalin-1 project in eastern Russia. Here there is a predominance of ultra-ERD wellbores coupled with considerable knowledge of the varying depth of the basement rock structure. This paper presents a process used for creating a geomagnetic crustal field model that can be updated to the actual survey location with the date and time for real-time application. This process can also be used in the reprocessing of legacy measurement-while-drilling (MWD) data. The application of this process significantly improves wellbore position accuracy. The ability to have a greater understanding of the overall geomagnetic field, along with enhanced techniques in multistation algorithm processing, removes the effects of drillstring and the cross-axial interference due to mud shielding effects. Additional benefits of this application include reduced wellbore tortuosity for planned wells, improved anticollision separation factors, and improved torque and drag profiles.
This new geomagnetic model, updated to the actual survey location, date, and time and incorporating realistic uncertainty determinations based on basement rock depth analysis, has resulted in a 50% improvement in the overall ellipse of uncertainty (EOU) when compared with previous definitive surveys, in addition to an accurate bottomhole location. Incorporating these advanced techniques reduces position uncertainty that improves overall 3D wellbore positioning. Other studies, such as a disturbance field study, evaluate the effects of the magnetospheric ring current, auroral electrojets, and secondary induced fields, and was conducted by analyzing the magnetic observatory data from the same magnetic latitude to quantify the maximum and minimum declination variations during a magnetic storm.
Kazakhstan has a world class endowment of petroleum resources including some of the world’s most fascinating and challenging super giants. With a large base of mature assets and the development of the Kashagan field, it is a good time to look for resources that will drive and sustain production levels for future generations. The oil and gas industry has a history of building reserves through frontier exploration, near-field exploration, and building reserves in existing reservoirs, through better definition of the reservoir and application of advanced technologies. All of these opportunities are present in the Republic of Kazakhstan: there is the enigmatic deep carbonate resource which is the focus of the ambitious Eurasia project; the further definition and development of Kazakhstan’s supergiants which can make large additions to their proven reserves; opportunities for nearfield exploration building upon existing infrastructure; and a large base of older producing fields which can be sustained through improved/enhanced oil recovery and new business approaches. The effort to add reserves in all of these areas is key to bringing on future production over the short, medium and long term.
Eight of the world's 10 longest wells have been drilled by ExxonMobil as operator of the Sakhalin-1 project in Russia. Components and drilling tools involved in the well design are evaluated and redesigned throughout the program to maximize penetration rate and reduce flat time. Drillstring-torque capacity was recognized as a limiter for increasing penetration rate and for reaching total measured depth capability. The operator consequently sought an alternative drillpipe connection with higher torque capacity. The Sakhalin-1 project comprises the Chayvo, Odoptu, and Arkutun Dagi fields off the east coast of Sakhalin Island, Russian Federation.
The Sakhalin-1 consortium has drilled a 15,000-m horizontal well from the Orlan platform at Chayvo field in the Sea of Okhotsk, topping four previous wells drilled between 2013 and 2015 that reached between 12,450 ft and 13,500 ft. Partner Rosneft described the well as "super complex" with a 14,129-m stepout drilled about 5 km offshore. Sakhalin-1 has been a proving ground for extended-reach drilling (ERD) technology since the first well was drilled there more than a decade ago. More recently, development well О-14 in 2015 was drilled to 13,500 m, well Z-40 in 2014 reached 13,000 m, and in 2013 wells Z-43 and Z-42 extended to 12,450 and 12,700, respectively. The longer horizontal wells eliminate the need for additional offshore facilities and pipelines, utilizing existing infrastructure to cut costs.
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.
Em, Iurii M. (Far Eastern Federal University Engineering School) | Morozov, Alexei A. (Far Eastern Federal University Engineering School) | Gulkova, Svetlana G. (Far Eastern Federal University Engineering School) | Gulkov, Alexander N. (Far Eastern Federal University Engineering School)
Magistral Gas Transmission System Sakhalin-Khabarovsk-Vladivostok (MGTS SKV) is filled with the gas from Sakhalin-3 gas fields, particularly from the Kirinskoye gas condensate field, which is equipped with a modern underwater production complex and a coastal gas preparation infrastructure. At the initial stage, the start-up and operation of the gas transmission system were accompanied by a number of malfunctions due to the formation of hydrate plugs.
At present, an increase of a thermodynamic hydrate inhibitor (THI) injection volume is the only way to prevent the formation of hydrates in the gas transportation system. The article proposes an improvement of the test procedure for calculation of inhibitor consumption.
An analysis of MGTS SKV natural gas has been made on a chromatograph Crystallux 400M. The result is shows a predominance of [CH4] 91.28%vol, a moderate concentration of [C2H6] 3.74%vol, [C3H8] of 1.61%vol, and [CO2] of 1.87%vol., a small content of [C4H10] 0.37%vol, [i-C4H10] 0.28%vol, and a negligible content of [C5H12] 0.04%vol, [i-C5H12] 0.09%vol, [neo-C5H12] 0.001%vol.
A temperature measurements were made in the range from −2°C to 20°C (271.15°K~293.00°K) and pressures from 6MPa to 11MPa (930~1560PSI). Gas hydrate phase formation and decomposition circles were made in samples with water previously exposed to pressure of 50MPa and 10MPa. Also, a distinction of experiments data between the Kinetics (K) and Hydrate Stability Zone (HSZ) methods has been described.
An experimental result shows that the hydrate formation process starts earlier in the sample with water exposed to pressure. A starting time of hydrate formation process normalizes in the next experiments. The duration of the hydrate formation process is longer than in a similar experiment with water without preparation.
It has been established that an additional tests with water exposed to pressure is necessary in the calculation of the THI injection volume. The formation of hydrates in such samples occurs earlier than in standard experiments.
With a large base of mature assets and the development of the Kashagan field, it is a good time to look for resources that will drive and sustain production levels for future generations. The oil and gas industry has a history of building reserves through frontier exploration, near-field exploration, and building reserves in existing reservoirs, through better definition of the reservoir and application of advanced technologies. All of these opportunities are present in the Republic of Kazakhstan: there is the enigmatic deep carbonate resource which is the focus of the ambitious Eurasia project; the further definition and development of Kazakhstan’s supergiants which can make large additions to their proven reserves; opportunities for nearfield exploration building upon existing infrastructure; and a large base of older producing fields which can be sustained through improved/enhanced oil recovery and new business approaches. The effort to add reserves in all of these areas is key to bringing on future production over the short, medium and long term. Topics to be addressed by speakers: Frontier exploration: The Eurasia Project Near field exploration In field reserves development Enhanced/increased oil recovery New business models Speakers: Kurmangazy Iskaziyev, JSC KazMunayGas Exploration Production Baltabek Kuandykov, Meridian Petroleum Askar Munara, Ministry of Energy, PRMS Bakytzhan Kaliyev, KPO Paolo Emilio Spada, ENI 13:30 - 14:30 Lunch 14:30 - 16:00 Technical Session 1: Formation Evaluation and Petrophysics Session Chairpersons Ahmed El-Battawy, Schlumberger and Assel Salimova, Baker Hughes Formation Evaluation and Petrophysics are key integrating disciplines within geosciences applied to finding and developing hydrocarbon resources.
Kershenbaum, V. Ya. (Gubkin Russian State University of Oil and Gas (National Research University), RF, Moscow) | Shmal, G. I. (Union of Oil & Gas Producers of Russia, RF, Moscow) | Panteleev, A. S. (Gubkin Russian State University of Oil and Gas (National Research University), RF, Moscow)
The PDF file of this paper is in Russian.
The development of the arctic shelf represents a great economic significance for Russia as it holds up to 80% of country’s hydrocarbons reserve. However, the production of hydrocarbons in that area is complicated by a delicate ecosystem and unfavorable climate conditions, specifically low temperatures in winter, strong winds and sea waves, seasonal presence of icebergs and pack ice. In this regard, the best solution for extracting oil and gas is the exploitation of the subsea production systems such as manifolds, flexible drill stem, control systems, underwater pipelines, subsea X-mas tree, transmitting and gas preparation systems. After the imposition of sanctions against Russia in 2014 there were some import substitution programs activated, and shelves development has become one of the most significant directions, due to the crucial dependence on the exported technology and products in this field. The import substitution program can be implemented only along with preparing standards that contain general requirements for the subsystems of subsea production complex on all stages of its life cycle. Obviously, applying these standards will help to accelerate market entry, decrease CAPEX and OPEX and ensure the equipment compatibility. Above all the standards requirements for the most important subsystems of subsea production complex should be issued, namely the ones for manifold systems, flexible drillstem and control systems. This article contains the analysis of API, ISO, NORSOK standards, the issues of applying them in Russian Arctic regions; it also gives some recommendations on the ways of Russian standardization development in the field of subsea production complex.
Освоение арктического шельфа является важной экономической задачей для России, так как именно там сосредоточено до 80 % углеводородных запасов страны. Однако наладить добычу в этом регионе непросто из-за тяжелых климатических, в частности, ветровых и ледовых, условий. В связи с этим наилучшим решением является использование подводных технических средств освоения: манифольды, шлангокабели, системы управления, подводные трубопроводы, подводная фонтанная арматура, подводные перекачивающие комплексы, подводные комплексы подготовки углеводородов и др. После введения санкций в отношении Российской Федерации в 2014 г. в стране развернуты программы импортозамещения. Одним из критически важных направлений стало освоение шельфа из-за крайне высокого процента зависимости от экспортных оборудования и технологий. Программа импортозамещения может быть реализована лишь при наличии стандартов, охватывающих весь жизненный цикл необходимой продукции. Применение таких стандартов позволит сократить издержки, обеспечить взаимную совместимость изделий для подсистем подводного добычного комплекса и ускорить выход продукции на рынок. В первую очередь должны быть выпущены стандарты по важнейшим подсистемам подводных добычных комплексов: манифольдам, шлангокабелям и системам управления. В статье проанализированы стандарты таких институтов по стандартизации, как API, ISO, NORSOK, проблематика их использования в Российской Арктике, а также даны рекомендации относительно пути развития отечественной стандартизации в области подводных добычных комплексов.