The operator piloted a new well-completion design combining inflow-control valves (ICVs) in the shallow reservoir and inflow-control devices (ICDs) in the deeper reservoir, both deployed in a water-injector well for the first time in the company’s experience. In this paper, the authors describe a project to design, field trial, and qualify an alternative solution for real-time monitoring of the oil rim in carbonate reservoirs that overcomes these disadvantages. The authors detail the development of a technique based on surface-to-borehole controlled-source electromagnetics (CSEM), which exploits the large contrast in resistivity between injected water and oil to derive 3D resistivity distributions, proportional to saturations, in the reservoir. This industry is one often considered reactive and overly tradition-bound. These new technologies, however—and, more importantly, the drive of these researchers to harness their capabilities—prove that petroleum engineers remain at the forefront of innovation and discovery.
Gaurav Seth, Ernesto Valbuena, Soong Tam, Will Da Sie, Hemant Kumar, Brian Arias, and Troy Price, Chevron Summary In this paper we present the results and analyses from an integrated simulation study focused on evaluating and selecting subsea boosting systems. The integrated model uses field-management strategies incorporating flowline routing, field and gathering-network constraints, and rate allocation. Novel techniques to model subsea networks enable selection of the boosting system and provide an improved understanding of dynamic conditions encountered in deepwater assets. The selected boosting system ensures safe and reliable operations while improving the project's net present value. Combining responses from reservoir and network systems into an integrated model to evaluate the subsea design requirements is a unique aspect of this study, because this involves novel modeling techniques for boosting systems (pumps). Analysis of these outputs leads to an improved understanding of field operation strategies, equipment selection and sizing, and production forecasts. The integrated model uses inflow performance relationships (IPRs) from reservoir simulation and vertical lift tables to generate performance curves (PCs), representing well deliverability as a function of tubinghead pressure. Comprehensive field-management logic uses the PCs to determine optimal well operating rates that satisfy all subsurface and surface constraints. This approach reduces a complex set of constraints to a single operating rate. Well operating rate is also a function of the pump power, the pump suction pressure, and the fluid phase behavior across the pumps. The integrated model delivers pump performance within its operating envelope and ensures equipment integrity. Two components of the subsea boosting system, single-and multiphase pumps, drove performance optimization and selection of system operating conditions. The study incorporated a comprehensive analysis of system constraints through implementation of complex field-management rules that accounted for well integrity (completions), performance of network equipment (valves, boosters, pump power requirements), facility capacities, and reservoir deliverability. The integrated study identified the different limiting system constraints throughout the life of the field and improved the overall efficiency of the gathering system. Use of PCs to reduce the constraints to a single operating rate provides tremendous computational performance improvement.
A major challenge when operating a gas lifted unconventional well is severe slugging. Without addressing its root causes, production fluctuation can remain for a long time and pose high risks to the entire operating system. This paper first reviews the gas lift for U.S. unconventional shale plays. Then it describes the major causes of gas lifted shale well slugging and proposes mitigation plans respectively, considering the implications on value and profitability. A systemic diagnostic workflow was developed for shale well slugging by combing production data analytics and dynamic simulation workflow. It also incorporated cost benefit analysis to evaluate incremental economic value. Transient modeling reveals key aspects of gas lift well slugging causes. A case study involving a shale well demonstrates the technical and economic impact of this transient behavior on gas-lift well performance. This study can assist operators in developing a mitigation plan for gas-lifted shale well severe slugging through transient simulation and in leading to substantial cost saving while extending asset economic life. It also demonstrates that transient multiphase flow simulation is an effective tool for the troubleshooting and the mitigation strategy selection for unconventional shale wells under gas lift.
Kuwait Oil Company (KOC) launched the Kuwait Integrated Digital Field GC1 (KwIDF-GC1) pilot project in 2009 as an investigation into how a cross-functional and cross-domain infrastructure could be established to aid in the achievement of corporate goals set for the following two decades. The company's vision for 2030 includes a philosophical shift in the way that the country's workforce accomplishes its tasks, employing the latest technologies and work processes. The project solution integrates field instrumentation, workflows automated in software, and focused collaboration. The Burgan oil field, the second largest in the world and the largest clastic reservoir, was discovered in 1938 and commercial oil production from it began in 1946. Production peaked in 1972 at around 2,400,000 barrels per day, and declined to around 1,700,000 barrels per day by 2005 [Croft 2013, Cordahi and Critchlow 2005]. Management of the reservoir has become increasingly challenging, partly due to damage that was incurred as the Iraqi invaders set fire to the wells during their retreat in 1991.
This project is a first in the State of Kuwait to instrument oil wells with pressure and temperature gauges, multiphase water cut meters and remotely automated chokes. Automation of the field was the first step in providing the advanced technology required of this project, realizing tangible advantages in minimizing the health, safety and environmental (HSE) exposure of field personnel. Wellsite data can be read, and choke positions can be set, remotely at the gathering center without the need for field personnel to enter hazardous areas. Work processes were converted into automated digital workflows supported by advanced network modeling and nodal analysis software in a state-of-the-art collaboration center. The collaborative teams use optimization and visualization software to contribute in real time to production operations that optimize production gains. Integration of multidisciplinary teams such as field development, sub-surface, production operations and maintenance in a real-time work environment enables proactive and reliable decisions to be made much more quickly than in traditional environments with disparate work teams. This paper describes how the various technologies and work processes are used by the collaboration teams during the pilot project to increase efficiencies in oil production.
A SCADA system is employed at the gathering center (GC) that interfaces with smart wellhead controllers and instruments. The implementation is digital throughout, employing a field-level WiMAX radio system to provide fast and secure Ethernet-based communication from the GC to the wellhead. At the wellhead, digital instruments provide real-time data for wellhead pressure, flow line pressure and temperature, flow/no-flow indication, and water cut. A remotely controlled adjustable choke governs the wellhead pressure to achieve desired flow characteristics. Selected wells contain highly accurate downhole pressure and temperature gauges. All instruments and control devices are interfaced through the smart wellhead controller. A proprietary closed-loop algorithm in the smart wellhead controller receives a set-point value for desired wellhead pressure from the SCADA system. The algorithm then controls the adjustable choke to maintain the pressure in the wake of fluctuating properties of the produced fluid from the well.
Cramer, Ron (Shell Global Solutions) | Krebbers, Johan (Shell International B V) | van Oort, Eric (Shell Exploration & Production) | Lanson, Anthony Paul (Shell E&P Technology Co.) | Palermo, Robert (Shell Oil Co.) | Murthy, Ajith (Shell Global Solutions) | Duncan, Peter (MicroSeismic Inc.) | Sowell, Tim (Invensys)
The Digital Oil Field (DOF) real time data structure as applied to drilling, reservoirs, wells surface production facilities, pipelines and downstream systems has evolved as bit of a muddle with little overall design and structure and little thought given to the underlying data foundational requirements.