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Kabdolov, Altynbek (North Caspian Operating Company) | Feltracco, Davide (North Caspian Operating Company) | Dupal, Ken (Kinetic Pressure Control) | Jones, Reese (Kinetic Pressure Control) | Zausa, Fabrizio (Eni) | Gandini, Gabriele (Eni) | Caia, Alessandro (Kwantis)
Abstract With the goal to exhibit leadership in industry process safety, North Caspian Operating Company (NCOC), Eni, and Kinetic Pressure Control have collaborated to evaluate the feasibility and potential process safety benefits from use of the Kinetic Blowout Stopper (K-BOS) technology in High-H2S and high-pressure drilling and completions and intervention applications from artificial islands in Kashagan field. The study focused on efforts to detect any showstoppers for the application of K-BOS, quantify the reduction in the blowout probability due to its application, and summarize the information currently available about the technology. Using the Eni proprietary e-wise™ fault tree analysis approach, a quantitative risk assessment was performed to compare the probability of a blowout in Kashagan field using conventional BOP systems to the probability of a blowout with the K-BOS added to the stack. The study also reviewed OEM provided operating procedures, a risk assessment for running the equipment, as well as a feasibility study regarding any height restrictions in the BOP stack and the position of the K-BOS in the stack. The impact of alternative equipment for risk reduction such as additional redundancy was also assessed. The application of the 13 5/8" 10M K-BOS system during reservoir drilling, completion and intervention operations significantly reduces the probability of a blowout by at least an order of magnitude. For drilling operations in the most challenging Rim portion of the reservoir, the blowout probability decreases by more than 90% and the residual value is below the blowout frequency for Producing Wells. The improved shearing/sealing capacity and reduced closure time provided by the K-BOS enable a reduced likelihood of a blowout and enhance the risk profile for the oil and gas industry.
Being ready to operate is one of the most critical steps in the development of an oil field. For complex projects characterized by technical risks and challenges, a structured approach is mandatory to ensure operational excellence and readiness. This study shows the methodology adopted by Agip KCO to achieve operational readiness for the Kashagan Field development project by means of a management system called Operations Readiness and Assurance (ORA). The ORA process assures that the field production facilities are designed, built, commissioned, and started up with account taken for lifecycle operations requirements. This will lead to a safe, cost-effective, and quick ramp up to target production levels.
Petrofac and joint venture partner Isker secured a $135-million engineering, procurement, construction, precommissioning, and commissioning (EPCC) contract with North Caspian Operating Company, operator of the North Caspian Project in Kazakhstan. The EPCC is for new water-treating facilities, and the scope of the 30-month project includes an inlet stream screening, feedwater tanks, oil skimmers, treated-wastewater storage and pumps, and sludge treatment and utilities. The North Caspian Project is the first major offshore oil and gas development in Kazakhstan, which covers the Kashagan, Kairan, Aktoty, and Kashagan South West fields. The Kashagan field has approximately 9–13 billion bbl (1–2 billion tonnes) of recoverable oil. The Kashagan reservoir lies 80 km offshore from the city of Atyrau in 3–4 m of water and is more than 4 km deep (4,200 m).
Bukharbayeva, Aigerim (North Caspian Operating Company N.V. NCOC) | Hatiboglu, Can (Karachaganak Petroleum Operating B.V. KPO, previously with NCOC) | Mtchedlishvili, George (North Caspian Operating Company N.V. NCOC) | Munsyzbayeva, Dinara (North Caspian Operating Company N.V. NCOC) | Uap, Berik (North Caspian Operating Company N.V. NCOC) | Muftakhidinov, Baurzhan (North Caspian Operating Company N.V. NCOC)
ABSTRACT This paper describes the application of Integrated Production System Modelling (IPSM) at Kashagan field. The IPSM is used for short-term, mid-term production plan and business plan forecasting, opportunity identification/validation and production optimization. The IPSM modeling strategy is to build fit-for-purpose model which produces accurate results with minimal running time. IPSM enables integration of surface network (GAP) and reservoir simulator through Resolve by Petroleum Experts. This in turn helps to replicate actual field performance by incorporating field management logic (script) and modeling relevant system constraints. While there are many constraints governing the maximum production in Kashagan field, they can be summarized into two main constraints: injection capacity and sulphur processing capacity. Modeling of the latter is essential to consider the impact of composition change over time. As a result of continuous improvement of existing model and close collaboration with multiple teams, IPSM model has proven its prediction capability with forecast accuracy of 99%. Current IPSM model is able to produce results for various streams: oil & gas production, gas injection, Sulphur throughput, etc. Additionally, IPSM demonstrated its importance in identification and evaluation of various production opportunities / threats as well as its need in influencing management decisions. After calibration of pipeline network to match actual data, a substantial potential opportunity of optimizing existing wells capacity was revealed. This is vital not only for short-term production optimization needs but also for long-term predictions. This paper presents several case studies and examples of application and value of Integrated Production System Model in the field. Learnings during implementation of a given feature are also described. Provided examples can be useful for other engineers practicing Integrated Production Model suite.
Nogerbek, Nurbol (NCOC) | Bukharbayeva, Aigerim (NCOC) | Ali, Samad (Schlumberger) | Amangaliyev, Bagdad (Schlumberger) | Shambulov, Mustafa (Shell previously with NCOC) | Hatiboglu, Can (KPO previously with NCOC)
Abstract Kashagan oil field has been under production since September 2016. The produced oil is associated with considerable amounts of sour gas that must be processed or disposed of while minimizing flaring. This paper will focus on the methodology for field development planning and production forecasting, incorporating gas reinjection and sulphur management with the objective of optimizing production, subject to operational constraints and bottlenecks at surface facilities. The field development plan includes reinjection of associated gas into the reservoir to increase oil production capacity at the surface and provide reservoir pressure support, while satisfying government regulations that do not allow continuous gas flaring. This requires analysis of H2S concentration and sulphur production, since the ultimate surface constraint at Kashagan field is sulphur processing capacity. We describe reservoir modeling workflows for oil production optimization with integrated logic for gas balancing. The impact of sulphur management on oil production is studied under different scenarios using a high resolution, fully compositional reservoir model. The procedures for management of the production facilities have been translated into reservoir simulation logic, including product streaming from facilities and processing constraints. This includes gas accounting and prioritization of gas with low H2S content to be processed at the sulphur recovery unit. The remaining gas with higher H2S content is sent back to the injection stream. Workflows have been developed using tailored scripting with user-friendly input of facilities constraints using spreadsheets to enable the model to be maintained in a ‘live’ state. Automatic allocation methods are used for prediction forecasting that penalize higher gas production wells but still provide incremental oil production. Development of a product streaming model allows for reporting of production of liquefied petroleum gas (LPG), dew-pointed gas, etc., in addition to the standard simulation results. The comprehensive guidelines provided in this paper can aid reservoir modeling and surveillance for a field through accurate analysis of actual operational constraints and bottlenecks as part of the planning process. The described gas and sulphur management logic provide pivotal information to enable the reservoir engineering and production teams to meet the challenges of development planning for a sour reservoir.
Stephens, Nat P (North Caspian Operating Company ExxonMobil Secondee) | Yergaliyeva, Bakyt (North Caspian Operating Company) | Zhazbayeva, Ainur (North Caspian Operating Company) | Uap, Berik (North Caspian Operating Company)
Abstract During early production of Kashagan Field, the surveillance program is critical for understanding connectivity within the reservoir. Pressure transient analysis (PTA) results in the rim facies of the Kashagan carbonate platform show well bore proximity to high permeability features. By integrating the PTA results in a fine-scale geologic model, the presence and magnitude of geologic features, including faults, karst bodies, and open fractures, can be evaluated as an explanation of pressure results. Good quality pressure transient data can be obtained from down-hole gauges during periods of production down-time. The character of the pressure-response can provide information to interpret reservoir properties such as permeability-thickness (kh) and the effect of geologic features in the vicinity of the well. In the Kashagan rim area, geologic features include seismically-visible karst features, seismically-interpreted faults, and open fractures that can be identified from wireline logs. Because fine-scale details of the flow properties could not be differentiated in the full field simulation model, a fine-scale sector model of the rim area was constructed using Petrel ™ software. By integrating the surveillance and geologic data, the subsurface team can make several key observations. Rim wells with cavernous karst features contain kh values up to two orders of magnitude higher than stratigraphically-equivalent platform interior wells. Wells that produce from open fractures in the rim are commonly adjacent to seismically visible faults and karst geobodies, and the distance from the well to the seismically-visible geologic feature is similar to the distance estimated from the PTA results. At present, the kh interpretations from PTA are the only direct estimates of permeability for the large geologic features in the Kashagan rim. In a fine-scale 3D sector model, the permeability of the geologic objects, including faults, karst geobodies, and open fractures is statistically distributed using the PTA results. The fine-scale sector model demonstrates the value of geologic and surveillance data integration in order to understand PTA results. By establishing a relationship between the distance to geologic objects and PTA-based permeability estimates, a powerful predictive model can be developed to better represent the flow along the rim and guide the placement of future drill-wells.
Abstract Wastes injection when implemented correctly allows reducing environmental impact and in many cases reducing projects costs. However, often such projects suffer the support from regulators, local communities as well as have little interest from technical professionals. The goal of the paper is to reduce the fear of wastes injection by sharing the acquired experience on waste injection project challenges and opportunities. The paper describes subsurface aspects of wastes injection projects in stages of feasibility and implementation, performed by operator for the offshore area in North Caspian Sea and onshore area in western part of Kazakhstan. The operator investigated several wastes injection opportunities in different time. Drill cuttings injection (DCI) was studied for two locations in the past and a pilot DCI project was successfully implemented in 2013-2014. Wastewater injection possibilities were studied for onshore locations for water injection from processing facilities. Currently the operator is pursuing the project, which will allow using a DCI well for the injection of wastewaters generated offshore.
Abstract In the early 2000, a consortium of Oil and Gas Companies operating the Kashagan, a super-giant oil field located in the North East of Caspian Sea, Kazakhstan area, embraced the challenge of maritime transportation in ultra-shallow waters, combined with a 5-months ice season per year and the potential risk of exposure to sour gas as a result of a blowout. The paper will present the ad hoc solution studied, tested and implemented for the first time in the naval architecture literature. A fleet of bespoke vessels was designed, model tested in the ice tanks of internationally recognized research centers, constructed and successfully tested in real scale in the field. For such vessels, unique of their type, Classification Societies were involved through all project stages, in order to comprehend these new technical characteristics, thus issue a new set of Class Rules accordingly. A multidisciplinary activity of reverse engineering was performed, involving Environmental, Metocean, Ice Engineering and Naval Architecture teams, starting from the probabilistic forecasted of the ice thickness, its temperature and corresponding actual tensile strength. Vessels structure and propulsion power were dimensioned as a direct consequence of that, allowed to achieve minimum weight, hence minimum draft. Such approach resulted in the construction of 2 highly specialized prototypes: the Mangystau, an ultra-shallow ice breaker for marine logistics supply chain, capable to break up to 1m level ice and navigate at 2.5m draft, as well as and the IBEEV, Ice Breaking Emergency Evacuation Vessel, intended to execute the task of EER - Emergency Evacuation Response, capable to rescue up to 340 people in ice infested waters, with the presence of an H2S toxic gas cloud. These pioneering vessels continue to support the development of the Kashagan oil field today. The novelty of the above is mainly constituted by the nonstandard approach to the problem, exploring for a new way to apply technology rather than applying an existing one, which resulted in the realization of vessel prototypes and the publication of new set of Class Rules.
Abstract Development of the Kashagan field is very complicated and encounters many challenges, such as a harsh offshore environment with an ice season, highly pressurized wells and a high H2S concentration (sour). All these challenges were known during the field construction phase, but after one year of production, another unforeseen challenge emerged– severe downhole scaling in certain oil producers, flowing at very low water cuts (<0.5% water). Scaling is a widespread and well-known phenomenon in many, often mature fields around the world, but it was not expected to occur in Kashagan in the early stage of field life. Well scaling developed very fast, leading to almost 50% productivity reduction on several wells in a few weeks time. Wellbore scaling put Kashagan production plans at risk, so it was critical to remediate the affected wells as soon as possible. A multi-disciplinary team started work to address the issue. For most "brown" fields, remediation of wells affected by scaling is a routine job. In the case of Kashagan, which had just started production, downhole scaling was a big challenge for various reasons. Firstly, when rapid productivity decline was observed on some wells, it was not clear what caused the impairment, and a lot of investigative work was done to identify the nature of impairment and root cause (mechanism) behind it. Secondly, scaling badly affected D-island wells, where SIMOPS well intervention capability is highly restricted. D-island is a hub for offshore processing and gas reinjection facilities, located just few hundred meters away from wells, and any well intervention requires the creation of a "yellow zone" and causes significant production deferment. Thirdly, it was clear from the beginning that remediation is a temporary measure, and that it was important to progress from "firefighting" mode to impairment prevention mode, for all wells. Despite all complexities of the task all affected wells were successfully brought back to production and, after various successful anti-scale treatments, fine-tuning of the scaling prevention process is currently ongoing. Due to the scaling, multiple processes had to be improved, such as metering, wells testing, wells surveillance and well interventions. In the design phase of the project, a well intervention was considered as something extraordinary, and expected to happen rarely, primarily for well integrity issues, not for scaling issues. Well intervention operations became a more routine operations and have started to play a critical role in the integrated activity planning process. This paper describes how Kashagan wells were affected by wellbore impairment and what actions were made to remediate wells and to return wells to its original productivity.
Abstract Miscible gas injection in the Kashagan platform started in 2017 and has been ongoing for three years. Gas injection in the platform carries both EOR and a facilities de-bottlenecking component. Initial flood assessment studies done using classical FD simulation have not provided the full picture of the reservoir dynamics to understand the performance of miscible gas injection. Areal reservoir depletion, pressure support and gas breakthrough events were challenging to quantify and characterize in terms of standalone full field FD simulation. Reservoir management strategy for operating the gas injection area was to maximize production from nearby producers and inject the full compressor potential. However, due to the fact that wells have different potentials driven by reservoir heterogeneity, areal distribution of cumulative reservoir fluid withdrawals and injection ended up being significantly different, which lead to flood pattern imbalances. The operator has implemented a modeling workflow that combines post-processing of history matched numerical simulation model with streamline tracing and integration of time-lapse well allocation factors (WAFs) to quantify and analyze flood performance. This paper presents how to use streamline modeling to estimate well-pair dynamic control volumes and a numerical integration workflow of the dynamic WAFs to evaluate pattern performance to guide flood balancing strategy. Streamline-based modeling workflow provides additional value by 3D visualization of the dynamic flood patterns and quantification of the individual pattern metrics. Numeric integration of injector-producer allocation factors (WAFs) and control volumes (CVs) allowed the construction of well pair conformance plots. Ranking of the patterns and I-P pairs filtered the outlier patterns with over injected and produced volumes and helped to focus on specific areas in need for pattern balancing. A list of producers with the highest pore volumes of gas injected were identified as at-risk wells for gas breakthrough and GOR elevation, which was confirmed by well test results. The first three wells with a rise in GOR and breakthrough sequence perfectly matched with the prediction of pattern performance. Those were identified as at-risk producers based on streamline modeling outputs. Verification of the analysis by field surveillance data gave confidence in reliability of the streamline-based flood evaluation approach. The outcomes of this study helped to understand miscible gas front movement and depletion dynamics in the gas injection area. This case study demonstrates how complementing finite-difference modeling with streamline analysis is necessary for achieving a complete assessment of the miscible gas flood performance.