During the last decades, CO2 sequestration in oil reservoirs has gained increasing attention for its potential economic benefits deriving from the application of CO2-EOR techniques. Within the framework of the Kyoto Protocol, this process becomes increasingly attractive due to the possibility of coupling enhanced recovery capabilities with carbon capture and storage.
This project focuses on a carbonate CO2-rich field located offshore North Africa. This field is currently produced flaring the associated gas, while future field development foresees the installation of a membrane module treatment. It will separate CO2 from hydrocarbon gas, with the possibility to export processed gas on one side and inject a stream of CO2-rich gas on the other side. This project aims at maximizing field recovery by optimizing the gas injection process. The main objective is to evaluate different gas re-injection strategies which could combine recovery enhancement and CO2 storage. A compositional reservoir model was considered to study the feasibility of injecting part of the produced gas into the reservoir, and evaluate its impact on the recoverable oil reserves and CO2 sequestration capacity of the reservoir.
Simulations were based on a miscibility study involving sour gas and resident oil mixtures. Even though the expected injection stream was found to be supercritical, and therefore liquid-like, at reservoir conditions, the gas-oil density difference is significant and CO2-rich gas displacement could not achieve miscibility conditions.
Numerical results indicated that injection schemes based on highly slanted wells and water alternating gas injection can overcome early gas breakthrough and a considerable amount of gas emissions, providing an improved sweep efficiency, a stable displacement and a significant degree of CO2 retention. Indeed, the incremental oil achieved in the best case is 15% with respect to the reference case without gas injection, and the CO2-rich gas retained in the reservoir is 63% of the total gas injected.
The design of a CO2 injection project and, more generally, a gas injection project, has to take into account the phase behavior of the injected gas and the reservoir fluid mixture. CO2 injection in oil reservoirs is strongly influenced by the phase behavior of CO2 and reservoir oil, which in turn are strongly dependent on reservoir conditions (T, P) and oil and gas composition. Benefits of CO2 injection consist in the reduction of capillary forces that impede the oil flow in the pore spaces, oil swelling and viscosity decrease due to development of mass exchanges between the reservoir oil and injected fluid, and possibility to achieve miscibility conditions (Tzimas et al., 2005; Lake, 1989).
The issue of BOP reliability has long been discussed and despite important advances it continues to generate concerns among offshore safety regulators. As for any safety barrier, it is difficult to know its true operational status during process operation. The idea of devising means and methods to somehow monitor the condition of the BOP in real-time has been in on the agenda of operators, contractors and regulators for quite some time. In this paper, we introduce the main functions of a real-time decision support tool related to the subsea BOP retrieval decision during drilling. The main goal of this new tool is to contribute to better-informed decision-making regarding operational safety and reliability of BOPs, while its ultimate purpose is to reduce BOP downtime thus reducing drilling costs while maintaining its safety margin. The Tool incorporates both qualitative and quantitative methods to help guide the operator decision-making after detection of a BOP component or subsystem failure during drilling. Entirely new in this Tool is the use of quantitative probabilistic criteria, which makes it a fully quantitative risk-informed decision support system. The computational engine is based on an advanced time-dependent reliability analysis of each BOP safety function before (normal condition) and after one or more detected component or subsystem failures. Results for the case of a real BOP operating in the North Sea are presented and discussed in this paper.
Together with the downhole safety valve (DHSV), the Blowout Preventer (BOP) is considered to be one of the most critical of the safety systems involved in offshore oil exploration and production operations. Both such devices are active emergency flow blocking ones, but the much higher complexity of the BOP puts it in a special place not only in comparison with the DHSV but amongst the entire set of offshore safety devices. The recent Montara and Macondo (Refs. 1 and 2) accidents have made it entirely visible to the whole world the huge consequences that can result when the BOP fails to perform its assigned safety functions. In addition, recent studies (Refs. 3 and 4) have shown that BOP unreliability is still responsible for 40-50% of drilling downtime, representing a cause of major losses to drilling contractors and oil operators.
Rapid CUBE is a deepwater blowout intervention tool designed to capture the hydrocarbons in close proximity of the leak, minimizing environmental consequences of the spill for the time necessary to regain control of the well. The system does not require any interface with the wellhead or BOP and is applicable to the most subsea incident scenarios. The design process of Rapid CUBE took advantage of lessons learned from the history of major incidents, specifically addressing deepwater operations and the weaknesses showed by open systems, such as hydrate blockage and very high seawater intake. The operating principle is based on quick separation of liquid and gas phases of the blowout, with the liquid hydrocarbons pumped to surface and gas released subsea. Innovative solutions had to be devised to overcome a number of technical challenges, such as the control of the gas/liquid interface inside the separator. From an engineering point of view, logistic requirements were among major design drivers to allow the system to be air-freightable and shipped worldwide in a few days.
The paper outlines the development of Rapid CUBE, from an innovative idea to industrial application. Rapid CUBE is now stored in its logistic base in Sicily.
In the last seven years the Oil&Gas industry, offshore drilling sector in particular, had to cope with the heavy heritage of the Deepwater Horizon incident, as will probably be the case also for some years in the future. The number of studies analyzing the independent causes, the technical, human and organizational factors as well as their combination grew in time, pushed by government agencies, academic institutions or independent firms. Industry was very responsive and investigation of the lessons learned came in parallel with the development of technical solutions, which of course took step from the results of the exceptional effort put in place during the emergency. In time, the capping stack technology, which allowed to stop the leak at the Macondo site, has been optimized and evolved in a dedicated business sector, with both oil companies and third party service providers as players.
Well-collision avoidance has gained greater importance as fields become more crowded and well paths increasingly complex. The safety and financial implications of shutting in production wells on platforms or repairing damaged wells have established a need for the industry to evaluate the potential for collision with a producing well.
When planning a drilling operation, evaluating the Risk is a main activity. Usually a collision into a producing well is one of the risk considered.
This paper / presentation elaborates how ClampOn has met this challenge by developing a real time monitoring system for detection of a drill bit in the proximity for existing wells. The ClampOn DSP Well Collision Detector developed, provides the operator with an advanced real time collision monitoring system with minimal equipment and personnel requirements. We will present the technology and field cases demonstrating the results.
The detectors provide drilling operators with real time data during the operation, thus supplementing collision risk analysis calculations and other available means for determining the bit’s proximity to existing wells. A drill bit in operation generates strong vibration and also high frequency acoustic noise. When the drill bit approaches an existing well, this noise penetrates into the well structure, and propagates over long distances within the well.
Any change in the acoustic conditions on the well heads is readily available for scrutiny as the operation commences and may provide early warning of the drill bit approaching an existing well. Upon observations of strongly increasing ultrasonic signal levels, drilling can be halted and data from available sources analysed. Depending on the analysis, the drill string may be diverted or drilling can resume with confidence that a collision has been avoided or that predictive calculations have been confirmed.
ClampOn’s passive acoustic sensors are used for many different applications; most common are sand monitoring, pig detection, leak detection, but also crack detection, and “well collision detection” (WCM). Common to all are acoustic emission, our instruments samples acoustic emission, and process the data specifically for the application. I.e. Sand impacting the steel of the flow line generate quite high frequent ultrasound, whilst a passing pig/scraper generate ultrasound in the lower frequency area. When a drill bit grinds its way through the rock formation, it generate acoustic emission. When the drill bit gets close to casings of existing wells, the acoustic emission will be transported through the rock, into the casing and up to the passive acoustic sensor attached at the wellhead.
The project “Personnel On Board (POB) in Real Time” is part of Eni Continuous Improvement initiatives and deals with people transport management on offshore installations. The main advantage is the possibility to have the information in Real Time of passengers on board (vessels/aircrafts – platforms) allowing also a better knowledge of offshore activities which can represent a support for the emergency response management.
The available and suitable technologies, constraints and requirements are the main factors considered during the technical analysis carried out to identify the optimal solution.
The solution adopted in order to track the offshore personnel transport consists of an “ad-hoc” hardware and software devices connected to an existing Eni tool.
Currently, the solution has been tested in Italy and in the near future, it will be implemented in Italy and in other countries.
The Oil and Gas industry is based more and more on activities with high HSE risks. In order to manage these risks, it is important to take under control the ongoing activities every time. The project “Personnel On Board (POB) in Real Time” has been developed to satisfy this requirement. The operations are based more and more on offshore activities, which need transport of personnel and materials to be carried out. In order to control these movements of people and materials, it is important to track the ongoing activities using a tool that collects all the important information.
This tool is an Eni software able to plan and optimize personnel and material offshore transport (by vessels and aircrafts).
Furthermore, it enables many operations to be mechanized, such as cost allocation, number of requests, stand-by time, fuel consumption optimization and vessel tracking. Currently, some information and operations regarding the scheduling of a trip are available on the Eni tool only after the end of the trip itself and need a manual input (i.e. the actual arrival/departure time of the vessel). Consequently, the integration between the existing tool and the results of the project Personnel On Board (POB) in Real Time improves the tool service and performance reducing the manual activity of trip scheduling and data updating of the software.
Over the last years Natural Gas has been posted as one of the most important fossil fuels of energy industry and the energy forecasting indicators have pointed that expansion in this sector will continue increasing significantly for the decades ahead. Therefore innovative offshore floating installations projects such as Floating Liquefied Natural Gas (FLNG) and LNG Regasification units started to be conducted all over the world in order to enable the development of the offshore Natural Gas resources. Subsea field development, topside process and shipping components are one of the greatest challenges of these projects since profitability highly depends on reliability, availability and maintainability of these systems. In order to optimize Capital Expenditure (CAPEX) investment and to provide guidance for future Operational Expenditure (OPEX) allocations, Reliability, Availability and Maintainability (RAM) analyses are performed in order to identify possible causes of production losses and assess possible system alternatives. The results of a complete RAM analysis enable to maximize client return on investment and to advice on process design improvement in a cost effective manner. Thus, the investment to improve the safety in the installation can be justified and consequently a greater confidence in performing process and transfer operations in LNG offshore units is achieved by experts involved in LNG activities. RAM analysis initiates when a base case model is established. Based on the base case results, sensitivity cases can be used to really add value and do so cost effectively in a controlled manner prior to costly changes in design. Sensitivity cases analysis focuses on the production drivers and it aims at analyzing how the bottlenecks found in the base case can be managed in order to achieve operating targets through changes in maintainability and operability. Based on that and by using typical case study examples, this paper will focus on how to identify these production drivers as well as how they can be applied to optimize send out production on Gas Floating units.
The importance of reliability analyses has increased in the last decades due to the greater complexity of the systems to achieve better efficiency and productivity as well as due to the severe consequences resulted from likely failures. Thus, reliability engineering can be used to control risk and manage the longevity and dependability of assets.
The Strategy adopted by Eni Company based on enhancing HSE culture within its management and towards its subsidiaries, helped achieving and maintaining a good level of performance in all aspects of its operations, and conduct its activities in a safe and responsible manner.
One of the concerns is how to enhance correlation between HSE Management System and HSE culture and to promote continuously leadership and commitment to improve and achieve very challenging results in HSE performance.
Eni implemented the HSE Management System inspired by the international standard OHSAS 18001 and ISO 14001 that sets elements with respect of a continuous improvement by conformance checks and demonstrates the principles by which the Company conducts its operations.
Challenging HSE proactive objectives are set to rethink the system as a whole, based on the different audit results, accident investigations and the commitment that top management is delivering to achieve a high level HSE performance, this will be through:
The following has been targeted and is still under workshops to ensure the suitability of the Company system:
The TOUGH family of multi-component, multiphase numerical reservoir simulators have a well know and a long history of applications in different fields of mass and heat transport in porous media. The use a full three-dimensional (3D) unstructured grid permits a great degree of flexibility to reproduce the geometry of complex geological formations and performs accurate reservoir numerical simulations. The full 3D Voronoi tessellation approach also allows reproducing the geometry of geological formations (useful, for example, in directional drilling). In this work, we present some applications of the 3D Voronoi pre- and post-processing software tools dedicated to the TOUGH family of codes (developed at the DICAM Department of the University of Bologna by the Geothermal research group), to study problems of gas migration in hydrocarbon reservoirs. In particular, a small set of 3D grids of a deep sedimentary formation has been created with VORO2MESH, and the simulation results analysed with TOUGH2Viewer.
VORO2MESH is a software coded in C++ able to rapidly compute the 3D Voronoi tessellation for a given domain and to create a ready-to-use TOUGH2 MESH file, up to million blocks. It is based on the well-known and powerful open source voro++ library.
The new extended version of the TOUGH2Viewer post-processor was used to easily inspect the 3D Voronoi discretization and to better manage the numerical simulation results. The software, written in Java, handles the visualization of both 3D grids (structured and unstructured) and simulation results.
This study shows the effectiveness of these tools, and that the use of unstructured grids, instead of structured grids, substantially improve both the reproduction of the geological model and the TOUGH simulation results.
The TOUGH  family of codes adopts the Integral Finite Difference Method (IFDM, [2,3,4]) for space discretization. The IFDM method needs that each interface (the surface separating two adjacent blocks) to be orthogonal to the line passing the two nodes of the blocks (also known as the orthogonality constraint). Cartesian structured grids satisfy this requirement, but they are not able in most cases to build complex shapes, such as for example the geometry of geological formations, without decreasing their dimension and increasing, therefore, the total number of blocks.
The challenges that the oil and gas industry is currently facing, in terms of continuous cash constraint issues and a prolonged period of volatile and relatively low oil prices, have pushed operators and suppliers to seek new and cost effective technologies, in order to maximize hydrocarbon recovery for producing fields and reduce investments needed for new developments. Specifically for offshore fields located in remote areas and at long step-out, several issues have to be solved, ranging from pipeline cost and flow assurance methodologies to control and power supply.
This presentation will focus on the latest developments in Aker Solutions portfolio of processing and power transmission technologies for long step-out subsea applications, targeting to reduce field development costs and minimize related risks.
By leveraging the operational experience from recent projects and a close cooperation across the supply-chain with key technology owners, a broad range of new system concepts and technologies have been developed, from optimized subsea compression systems to AC power transmission. Results from the qualification work and testing for some of these technologies will be presented.
Subsea gas processing and boosting, recognized as one of the most promising set of technologies for long distance step-out offshore fields, is the application of hydrocarbon processing equipment at the seafloor for conditioning and pressure boosting of well stream fluids.
With the recent success of Åsgard Subsea Compression for Statoil and Ormen Lange Subsea Compression Pilot for Shell, subsea processing is attracting interest because of its ability to increase production, enhance reservoir recovery and improve field economics. In addition extensive technology qualification programs have been completed preparing a large number of components for use in subsea processing applications.
Flow assurance is one the governing parameters for the selection of the field development concept for long tie-backs, in order to ensure unobstructed and controllable flow from the wells to the processing facilities. This is achieved by correctly sizing and specifying the production equipment and the use of chemicals or heating, as well as designing operating procedures to be performed at start-up, during production, and when shutting down the system.
Underground gas storage (UGS) into aquifers causes a limited dissolution of gas into the water at the gas-water interface. This phenomenon was characterized and quantified in a study carried out at a UGS site in an aquifer in the Parisian Basin (France).
The study methodology consisted of simulation of water and gas phase equilibrium and comparison of the results with in-situ measurements.
Reliable downhole gas/water holdup data were obtained by modifying a wireline tool based on optical refraction, discriminating gas from liquids and deriving a direct gas holdup. The modified optical tool was combined with an inline spinner and pressure and temperature sensors to allow an optimal evaluation of the zones of interest. Data were acquired in a monitoring well in flowing conditions (25 m3/day water). The survey was recorded from surface down to the producing water interval, revealing gas bubbles freeing from solution only at shallow depth, above 47 m.
Water was also sampled at reservoir conditions with a dedicated wireline tool. The samples show stable concentrations of dissolved gas over time, with methane as the prevalent dissolved gas.
Phase equilibrium was calculated at multiple depths using different thermodynamic equations of state and models. Results from PSRK and MHV2 models, including nucleation overpressure effects, fit well with the acquired data.
Thanks to the innovative logging tool and procedure, the consistency between the acquired and simulated data and the results of the equilibrium models, there is enhanced confidence in the thermodynamic modelling for UGS. The results from this analysis can be now integrated in a reservoir simulator to model the gas/water phase exchanges with a better accuracy.
This workflow can also be applied to other UGS fields for water and gas equilibrium modelling.
Underground gas storage (UGS) into aquifers causes a limited dissolution of gas into the water at the gas-water interface. A study was carried out for the characterization and the quantification of the phenomenon at a UGS site in an aquifer. In-situ measurements of the gas/water holdups were made in a monitoring well, with water samples collected at reservoir depth and along the well using a wireline down-hole measurement technique. The in-situ measurements allowed the validation of a theoretical thermodynamic model of dissolution.