Pavlov, Dmitry (Sakhalin Energy Investment Company Ltd.) | Fedorov, Nikolay (Sakhalin Energy Investment Company Ltd.) | Timofeeva, Olga (Sakhalin Energy Investment Company Ltd.) | Vasiliev, Anton (Sakhalin Energy Investment Company Ltd.)
This paper summarizes the results of 3 years collaborative efforts of the Geophysicist, Production Geologist and Reservoir Engineers from the Astokh Development Team and a Geochemist from the LNG plant laboratory on integration of reservoir surveillance and reservoir modelling.
In period 2015 – 2018 a large bulk of geological and field development data was collected in Astokh field, in particular: cased and open hole logs, core, open hole pressure measurements, flowing and closed-in bottom hole pressures, well test data, new 4D seismic surveys (2015, 2018), fluid samples. Since 2016, essential progress was made in oil fingerprinting for oil production allocation in Astokh field. Simultaneously, the need for update of static and dynamic models was matured upon gaining experience in dynamic model history matching to field operational data (rates, pressures, well intervention results). In other words, the need in update of geological architecture of the Astokh reservoir model was matured upon reaching critical mass of new data and experience. To revise well correlation, it was decided to combine different sorts of data, in particular seismic, well logs and core data and reservoir pressures. Different pressure regimes were identified for 3 layers within XXI reservoir. Pressure transient surveys were used for identification of geological boundaries where it's possible and this data was also incorporated into the model. Oil fingerprinting data was used for identification of different layers and compartments. Integration of pressure and oil geochemistry data allowed to identify inter-reservoir cross-flows caused by pressure differential. Based on all collected data, sedimentology model and reservoir correlation were updated based on sequential stratigraphy. As a result, a new static model of main Astokh reservoirs was built, incorporating clinoform architecture for layers XXI-1' and XXI-2. To check a new concept of geological architecture material balance model was used and matched to field data
Integration of geological and field operational data provided a key to more advanced reservoir management and development strategy optimization. Based on updated reservoir model, new potential drilling targets were identified. Also, with new well correlation, water flood optimization via management of voidage replacement ratio was proposed. The completed work suggests essential improvement in reservoir modelling process by inclusion of various well and reservoir surveillance data.
The paper consists of the following sections: Introduction Field geology Field development history Scope of work complete and main results Proposed well correlation update for XXI-1' and XXI-2 layers Integration of well logs, pressure and fluid analysis data Connectivity between layers XXI-S, XXI-1' and XXI-2 Integration of pressure and oil fingerprinting data Connectivity within layers XXI-S, XXI-1' and XXI-2 Results of pressure interference tests Testing of new well correlation concept in material balance model Proposed reservoir correlation updated based on seismic data New geological concept New depositional model Integration of core data Changes in reservoir architecture Conclusion Main results and impact on field development
Field development history
Scope of work complete and main results
Proposed well correlation update for XXI-1' and XXI-2 layers
Integration of well logs, pressure and fluid analysis data
Connectivity between layers XXI-S, XXI-1' and XXI-2
Integration of pressure and oil fingerprinting data
Connectivity within layers XXI-S, XXI-1' and XXI-2
Results of pressure interference tests
Testing of new well correlation concept in material balance model
Proposed reservoir correlation updated based on seismic data
New geological concept
New depositional model
Integration of core data
Changes in reservoir architecture
Main results and impact on field development
In this paper, the approach to multivariate static and dynamic modeling is considered on the example of an offshore field discovered in 2017. Based on the limited volume of information, the quantitative and qualitative description of uncertainties included further in the 3D modeling is made. This model is proposed to be used as a tool for prompt decision making when implementing a fast-track project with limited time between exploration and pre-FEED stages.
A number of companies are pushing for alternative approaches to offshore development that seek to access marginal reservoirs. Their differing and unique ideas call for a departure from the usual playbook, but share a common goal of slashing capital costs. Eight of the world’s 10 longest wells have been drilled by ExxonMobil as operator of the Sakhalin-1 project in Russia.
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.
Moving their directional drillers into their Houston real-time remote operations centers has improved drilling efficiency for two of the top shale producers. This paper presents a factory-model approach to improving CT drillout performance that has been used successfully for more than 3 years and has become standard practice. The oil industry is currently undergoing a technological transformation that will add value, improve processes, and reduce cost. Future drilling engineers will have knowledge of robotics, automation, and organizational efficiency, which is highly appealing for recruitment. This paper describes challenges faced in a company’s first deepwater asset in Malaysia and the methods used to overcome these issues in the planning stage.
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.
The drilling records of Extreme Reservoir Contacts (ERC) like Extended Reached Drilling (ERD) and Multi-Lateral wells(ML) continue to be broken. From the initial limit of MD 10,000ft to now almost 50,000 ft with extended reach depths and from dual-lateral to quad-laterals’ with 40,000-50,000ft reservoir contact. Completions rule of engaging with this type of wells continues to play ‘catch-up'. As a result, getting the full potential out of these extreme wells with limited completions options had always been a challenge. Recent innovation in "wireless electric connect/disconnect" technology combined with all electric integrated intelligent completions architecture has addressed these challenges. The well completion design is an all electrical system that provides a multi trip connect/disconnect system enabling seamless communication between upper and lower completions enabling permanent downhole monitoring and control, at the sand face. The highlight of this digital edge solution and deployment architecture enables completions to deploy in ERC wells meeting targeted drilled depths and achieving reservoir goals. The digital enablement provides real time downhole data for permanent production logging and zonal well testing capability while producing. Production and reservoir management is at finger tips of the end user.
A new innovative down hole electric telemetry enabled data transmission and power to be distributed across multiple sensors like pressure, temperature, water cut and electric flow control valve. Run on a single electrical cable, this digital completion technology with its induction coupling capability continue to complete record-drilling wells and makes today's completions limitations a history. It is now a reality for fully-digitalized Intelligent Completions solution, which can support any well type scenarios; multi-zones, horizontals, multi-laterals and extended reached drilling (ERD), including subsea completions. Each zone can be equipped with a permanent downhole infinite position valve-control, flowmeter, water-cut sensor and/or pressure/temperature gauges. This allows real-time reservoir measurement and supports ‘Dial A Rate’ flow control. Conventional flow control valves depend on hydraulic actuation system, although the technology has worked for decades, it has some inherent limitations such as need for multiple control lines limiting the number of zones, maximum depth of deployment as well the response time of hydraulic systems for very long completions. Electric valves are free from these limitations by design and provides lot more flexibility in the hands of the completion engineer. The multiple sensors measurement and data integration is achieved with a single surveillance, monitoring, diagnostics and valve-optimization production software to ensure real time data streaming, management and bringing insights to production and reservoir engineers for production optimization through remote valve control.
This digital solution of Intelligent Completions technology can finally claim that completions is no longer the limiting factor, effective reservoir management with intelligent completions can follow wherever the drill bit can go. It has been deployed worldwide from the Middle East to the open Sea in Pacific to enable zonal production-control and reservoir management. Its borderless completions architectures and standardization of modular system is the answer for Digital Oilfield and Data driven continual production optimization and reservoir management without intervention.
For the first time in Completions history, extended drilling records are matched with completing the entire well to Measured Depth (MD) with fully digitized solution of multi-zone measurements, infinite-control valves and real time data enabled production optimization system.
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.
The paper presents the results of a multiparametric analysis of the helium saturation zone after its injection into a porous gas reservoir, the dynamics of its content in a withdrawn gas mixture and the helium recovery factor (target parameters). The calculations are performed on a three-dimensional composite hydrodynamic sector model of a homogeneous anisotropic reservoir of a virtual gas deposit. Based on the results obtained, the geological and technological factors are ranked according to the absolute value of the change of target parameters when the input parameters change. The dynamics of the influence of geological and technological factors on the target parameters is described concerning different withdrawn gas volume from the initial reserves. The identified relationships can be useful for planning of the experimental helium injection and the placement of exploitation wells at underground helium storage.
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.