Africa (Sub-Sahara) Cairn Energy has flowed oil from its SNE-2 well offshore Senegal. Drillstem testing of a 39-ft interval achieved a maximum stabilized but constrained flow rate of 8,000 B/D of high-quality pay. A flow rate of 1,000 B/D of relatively low-quality pay was achieved from another zone. Drilled to appraise a 2014 discovery, the well lies in the Sangomar Offshore block in 3,937 ft of water 62 miles from shore. Drilling reached the planned total depth of 9,186 ft below sea level. Cairn has a 40% interest in the block with the other interests held by ConocoPhillips (35%), FAR (15%), and Petrosen (10%).
Although conformance-improvement gel treatments have existed for a number of decades, their widespread use has only begun to emerge. Early oilfield gels tended to be stable and function well during testing and evaluation in the laboratory, but failed to be stable and to function downhole as intended because they lacked robust chemistries. Also, because of a lack of modern technology, many reservoir and flooding conformance problems were not understood, correctly depicted, or properly diagnosed. In addition, numerous individuals and organizations tended to make excessive claims about what early oilfield gel technologies could and would do. The success rate of these gel treatments was low and conducting such treatments was considered high risk. As a result, conformance-improvement gel technologies developed a somewhat bad reputation in the industry. Only recently has this reputation begun to improve. The information presented in this chapter can help petroleum engineers evaluate oilfield conformance gels and their field application on the basis of well-founded-scientific, sound-engineering, and field-performance merits.
Intelligent wells are downhole flow control devices, sensors, power and communication systems, and associated completion equipment. This equipment is used to optimize production, improve recovery, and manage well integrity. Developing an intelligent-completion solution requires the clear definition of well and/or project objectives. Initially flow control devices were based on conventional wireline-operated sliding-sleeve. These valves were reconfigured to be operated by hydraulic, electrical, and/or electrohydraulic control systems to provide on/off and variable position choking.
Since the inception of the technology in the late 1990s, the use of intelligent well technology has focused on production acceleration, increased ultimate recovery, reduced operating expenditure (opex) and reduced project level capital expenditure (capex). The following examples illustrate applications in which this technology has been deployed. Using optimization, the strong lateral is restricted and more chance is giving for the weak one. This cannot be obtained without a downhole valve and surface control in addition to modeling. Objective Achieve production increase based on DTS analysis.
Included are applications of foam for mobility control and for blocking gas. In 1989, Hirasaki reviewed early steam-foam-drive projects. In 1996, Patzek reviewed the performance of seven steam-foam pilots conducted in California. Early and delayed production responses were discussed for these pilots. Gauglitz et al. review a steam-foam trial conducted at the Midway-Sunset field of California.
Africa (Sub-Sahara) Kosmos Energy has made a significant deepwater gas discovery off Senegal. The Guembeul-1 well in the northern part of the St. Louis Offshore Profond license in 8,858 ft of water encountered 331 net ft of gas pay in two excellent-quality reservoirs, the company reported. The results demonstrate reservoir continuity and static pressure communication with the Tortue-1 well, which suggests a single gas accumulation. The mean gross resource estimate for the Greater Tortue complex has risen to 17 Tcf from 14 Tcf as a result of the Guembeul discovery, the company said. Kosmos, the operator, has a 60% interest in the well. Timis (30%) and Petrosen (10%) hold the remaining interest. In Salah Gas has started production from its Southern fields in Algeria.
Recent developments of new ultra-deep logging-while-drilling (LWD) resistivity tools have increased usage for on-demand computational infrastructure. The tools are capable of providing much deeper determinations on formation geologies than conventional electromagnetic (EM) resistivity tools, allowing more accurate real-time wellbore adjustment and optimization. This technique efficiently explores reservoir insights for maximizing oil production; however, the time to process raw measurements into useful geological information is long owing to the complexity and large amount of data associated with the tools. The conventional computation platforms are not efficient enough for both real-time and post-well formation evaluations based on this tool's measurements. This paper introduces a high-performance computing (HPC) platform which provides flexibility among different deployment architectures and large-scale cloud infrastructure. This enables numerous computational resources to quickly process raw data and provide the information needed to successfully steer a well. The new HPC platform has 50% more efficiency compared to conventional parallelization methods, such as Open Multi-Processing (OpenMP), using same amount of CPUs. Furthermore, faster computation is achievable owing to the scalability of the HPC implementation as well as the flexibility of available assets in the cloud or on-premises environments, which are beneficial for applications with heavily computational requirements and short time constraints.
Ahmed Elfeel, Mohamed (Schlumberger) | Tonkin, Trevor (Schlumberger) | Watanabe, Shingo (Schlumberger) | Abbas, Hicham (Schlumberger) | Bratvedt, Frode (Schlumberger) | Goh, Gordon (Schlumberger) | Gottumukkala, Varma (Schlumberger) | Giddins, Marie Ann (Schlumberger)
Traditional reservoir management relies on irregular information gathering operations such as surface sampling and production logging followed by one or several treatment operations. The availability of both diagnosis and the prescribed remedial operations can cause severe delays in the reservoir management cycle, increasing unplanned down-time and impacting cash flow. These effects can be exacerbated in remote and offshore fields where well intervention is time-intensive.
A new, innovative, all-electric, flow control valve (FCV) is now a reality for smart completions. This can support any well penetration scenario including multiple zones per lateral in maximum reservoir contact wells and multi-trip completion in extended reach wells. Each zone is equipped with a permanent intelligent flow control valve, allowing real-time reservoir management and providing high-resolution reservoir control. Valve actuation is semi-instantaneous and field data has shown that the frequency of updating such valves is at least 50 times compared to conventional valves, enabling near continuous closed-loop reservoir management. However, such a high frequency optimization demands computational efficiency as it challenges existing optimization applications, particularly when multiple realizations are considered to account for reservoir uncertainty.
In this paper, we present a framework to support field-wide implementation of smart FCVs and hence maintaining a fast closed-loop reservoir management. The framework consists of history matching using Ensemble Kalman Filters (EnKF) where smart FCV data is assimilated to condition a suite of representative reservoir models at a relatively high frequency. Thereafter, a reactive optimizer utilizing a non-linear programming method is applied with the objectives of maximizing instantaneous revenue by determining the optimal positions of the downhole valves under user defined rate, pressure drop, drawdown and setting constraints. This optimization offers production control planning suggestions with the intent of immediate to short-term gain in oil production based upon the downhole measurement and the performance of the near wellbore model. At the same time, a proactive optimizer can be used to determine valve-control settings for longer term objectives such as delaying water/gas breakthrough. The objective of this optimization is equalization of the water/gas front arrival times based upon generation of streamlines and time-of-flight (TOF) analysis. Both modes of optimization are performed efficiently such that a single optimization run is sufficient per geological realization. We use the OLYMPUS reference model, a water flooding case, to demonstrate the workflow. The reactive optimization shows an increase of 25% in the net present value through minimizing water production and increasing injection efficiency, while proactive optimization delays water breakthrough time by 2-4 years. The paper showcases the effectiveness of complementary workflows where high frequency reactive and proactive optimizations support a near continuous closed-loop reservoir management.
One of the latest offshore innovations from Statoil is nothing flashy, which is the point. A drawing shows a plain, steel jacket, standing in water 110 m deep, topped with a flat metal deck. The spare design is indicative of the disciplined approach to offshore development that led to a 52% decrease in the estimated break-even cost for its Oseberg Vestflanken 2 project, of which the platform is a key part. The lower break-even made it possible to move forward with development of three small oil and gas fields at a time when depressed prices are forcing mass cancellations of offshore projects globally. Cost-cutting programs have become the rule since oil prices plunged.
Rinde, Trygve (Acona Flow Technology AS) | Killie, Rune (Acona Flow Technology AS) | Lager, Totte (Acona Flow Technology AS) | Solberg, Tron (Acona Flow Technology AS) | Bakli, Mikkel (Acona Flow Technology AS) | Grüner, Vegar (Acona Flow Technology AS)
Breakthroughs of water and/or gas in production wells may have direct consequences for the production rates and overall field recovery factors. Multiple technologies have recently been developed to autonomously control inflow from the reservoir. Common to all these technologies is that new limitations are introduced which may have a negative impact on the well. This paper presents the design process for the next generation inflow control system and introduces new requirements for such completions.
Traditional Passive Inflow Control Devices (ICD) are designed to act in a preventive manner by setting up a somewhat more even inflow profile along the reservoir section and thereby delay the breakthrough of gas or water. More recently, several new initiatives have been presented which will operate autonomously and try to choke back unwanted production. Common to all these technologies is that viscosity differences are used to identify the flowing fluid phases. Viscosity differences between the reservoir fluids are therefore mandatory for these to work.
In this work the design process has been given an operational focus and the following requirements for the next generation autonomous inflow control devices have been defined: easy to install as an integrated part of the downhole completion robust in design and functionality secures complete clean-up of mud and completion fluids independent of fluid viscosity negligible pressure drop during normal production allows back-flow of fluids
easy to install as an integrated part of the downhole completion
robust in design and functionality
secures complete clean-up of mud and completion fluids
independent of fluid viscosity
negligible pressure drop during normal production
allows back-flow of fluids
In this paper a new design is proposed for the next generation autonomous inflow control valve which is independent on differences in fluid viscosities. The proposed valve blocks, or restricts, production of unwanted water or gas, and re-opens for production if oil comes back. It can be designed to stop water/gas production at a predetermined WC/GOR. Furthermore, the valve ensures efficient clean-up along the full length of the reservoir section and is insensitive to exposure to mud, particles and filtercake. The valve will not restrict any future well operations and can be designed with a fail-safe option.
The new design of autonomous inflow control systems represents a great technological improvement which will ensure robust, economical and fail safe design as well as removal of typical operational envelopes necessary for traditional technologies.