Workshop Discusses Framework for Successful EOR Project
More than 130 professionals comprising geoscientists and engineers, government officials, executives of public and private operating firms and service companies met in May in Manta, Ecuador, for a workshop on enhanced oil recovery (EOR). The workshop, titled “EOR: Technical and Managerial Framework for Ensuring a Successful Implementation,” covered the successful implementation of EOR projects, including the design and essential criteria for evaluating a pilot project, technical complexities, experiences, results from several international projects, implementation costs, and time to achieve commercial results.
EOR processes have been applied for decades, with steam injection, gas injection, and polymer injection the most common. Steam injection is used primarily in producing heavy and extra-heavy oil in shallow reservoirs; however, further research is needed for its application in deep reservoirs. Enhanced recovery through gas injection (hydrocarbons, nitrogen, and CO2) has increased rapidly in recent years because of its low risk, and has interesting potential for use in carbonate reservoirs. The main challenges for CO2 injection processes are the availability and distribution to candidate fields.
Successful implementation of enhanced recovery processes require detailed geological knowledge of the reservoirs. Therefore, it is important to plan and execute appropriate actions for the acquisition and interpretation of data that will allow adequate characterization of the reservoirs and their fluids, thus reducing uncertainty in the understanding of the underground formations.
With data gathered from the reservoir and its fluids and with the scrutiny rules developed in the past several decades, it is possible to establish initial alternatives for enhanced recovery efficiently. It is noteworthy that these preselection criteria should not be taken as absolute rules; they are useful as a practical tool used by specialists with experience in enhanced recovery techniques. Data mining tools that complement the scrutiny work have been recently developed.
Laboratory experiments are needed to define the most appropriate EOR process and the formulation to be injected. Estimate in the laboratory also help in understanding the recovery potential (recovery factor), and the main mechanisms responsible for the displacement of the remaining oil. Among the most relevant aspects for evaluation are interfacial phenomena, phase behavior, capillary pressure, relative permeability, minimum miscibility pressure, and the interaction between fluids and reservoir stone. With efficiency in mind, laboratory studies should be performed in parallel with other phases of the process, such as reservoir characterization.
Results obtained in the laboratory must be adapted and scaled before implementation in the reservoir. Scaling of the various parameters must be done carefully considering the particularities of the field under study so the models can predict the behavior of the enhanced recovery method in the well
The most common way to bring laboratory results to reservoir scale is by conducting a pilot on a small, representative section of the reservoir. The selection, objectives, and evaluation of the pilot are crucial, because this will help reduce uncertainty in the performance of the EOR process to be implemented at field scale. Pilots should not necessarily be profitable, but should look for and, ideally, present a value promise. Proper planning, setting objectives that the pilot must reach, and implementation of a monitoring program are essential elements for a successful pilot.
Proper project management increases the probability of a successful EOR project at field scale. Sample data, laboratory analysis, and tools to predict the behavior of the recovery process, both underground and on the surface, should be documented in detail. The program should be the standard for tracking metrics during the life of the project. Adequate project management should take into account the challenges such as fluid supply, infrastructure, technology, and qualified technical resources. The tracking and monitoring of technical and organizational variables are vital to implementing EOR successfully and ensuring that risks that could jeopardize the project’s success are anticipated.
The availability of qualified human resources is a key to a successful EOR project. The oil and gas industry must develop young engineers with a strong understanding of geoscience, organic and inorganic chemistry, fluid mechanics, thermodynamics, reservoir engineering, and related areas. Companies should create multidisciplinary teams led by experts to oversee the implementation and monitoring of EOR processes.
Government has played an important role in the development of EOR technologies, especially through tax incentives, which are essential for starting projects that require large investments with considerable risk.
Workshop participants drew several conclusions, including:
- The oil industry should initiate the systematic development of EOR projects, which will be essential in developing production in the near future.
- The short-, medium-, and long-term success of EOR projects will rely on having the right technology, project management, technical training, and a regulatory framework that encourages research and execution of these projects.
- EOR technology is available and, at current oil prices (and those predicted for the future), the probability of a positive net present value for EOR is greater than 90%. These projects must be conceived, designed, and implemented timely. EOR production has a higher cost than, and is not intended to compete with, primary production, but EOR is cheaper than importing crude oil or other alternative energy sources.
- Thermal methods are still the main alternative process in producing heavy and extra-heavy crude oil, particularly in shallow reservoirs.
- Gas injection is becoming more widely used because of its low risk compared with other methods, particularly in carbonates. The availability and distribution are the main challenges of CO2 injection.
- The main objective of a pilot program is to reduce risk and its selection is crucial. The objective should not be economic return, but to prove value.
- Agreements between private and state-owned companies that encourage the training of technical personnel specialized in EOR and allow knowledge transfer are keys to the successful implementation of these projects and should be strengthened. In addition, technical partnerships between operators involving universities should be used.
Workshop Covers Subsea Processing Issues
An SPE Applied Technology Workshop (ATW) on subsea processing recently took place in Stresa, Italy. The workshop was divided into sessions covering concept development, subsea boosting, subsea compression, subsea power, subsea separation, and operational experience. Each session included topic presentations, question-and-answer sessions, and mini-workshops allowing participants to interact, learn, and share from one another.
Subsea processing is allowing increased recovery, lower capital and operating expenses, and health, safety, and environmental (HSE) benefits. Subsea processing success stories are increasing in number and during the workshop participants heard that:
- Petrobras has extensive experience from subsea electric submersible pumps (ESPs) and has recently applied subsea mudline multiphase pumping (MMP) pumps at the Barracuda field, subsea raw water injection pumps at the Albacora field, horizontal mudline ESP skid at the Espardarte field, and a subsea gas/liquid separation system and an oil/water separation system at the Marlim field.
- At the Vincent field, Woodside has applied a subsea MPP system, including two off multiphase pumps. The processing system has given accelerated production and increased the availability of topside facilities and will extend the production life of wells.
- Pazflor’s subsea separation units (SSUs) have been in operation and operator Total considers the project a success for subsea processing. SSUs make topsides facilities easier to operate.
- Statoil and Shell are confident that the technology can be deployed at Ormen Lange.
Rigorous qualification testing, access to good test facilities, and a stepwise development of technologies are important factors to succeed with the implementation of new subsea processing technologies and to mitigate risk. Communication of success stories and a correct allocation of risk for subsea processing technologies are critical to the selection of subsea processing solutions by decision makers.
Concrete new subsea separation projects and business cases are relatively few and there seems to be less confidence and some confusion about the maturity of separation technologies. Several suggestions for improvement were discussed during the workshop. Generally, oil companies have confidence in subsea processing solutions, but costs are becoming a serious issue. If costs continue to increase, deployment of new technologies could be hampered.
During the workshop, participants discussed two needs:
- More standardization. Standardization of technology readiness level (TRL) level definitions, subsea process interfaces, topside interface, design codes for subsea pumps, subsea compressors, and subsea separators have been suggested. Subsea power standardization is ongoing through joint industry projects (JIPs) and it was suggested to evaluate if the same model could be applied to other aspects of subsea processing.
- Increased collaboration, especially through the use of JIPs.
Below are some of the highlights of the workshop discussion
Opening and Keynote
The workshop opened with a summary of the three previous SPE ATW on subsea processing held in 2006, 2008, and 2010. Recurring themes of the previous workshops have focused on the need for standardization, technology qualification/test facilities, and subsea power. Several questions were presented to the panelists:
- What are the new concrete opportunities? Where in the world are they and when will they be realized?
- Why is subsea processing finally “happening now”? What has changed?
- What will it take to succeed and extract full value from subsea processing now and in the future?
- Can suppliers deliver in a heated market?
- How much of a “problem” are partners?
- Are today’s technical requirements sufficient/mature enough for subsea processing?
- Are we designing for obsolescence in today’s subsea processing systems?
Subsea processing has been happening in Statoil for some time starting with the Lufeng subsea single phase pump in 1997. Subsea processing will play an important role in Statoil, reaching its production target of 2.5 MBOEPD in 2020, up from today’s 1.8 MBOEPD, and increasing Statoil’s recovery rate from today’s 50% to 60%.
Subsea processing is happening now because subsea processing gives increased recovery, lower capital and operating expenditures, and HSE benefits—enabled by a stepwise and extensive development of subsea production and subsea processing technologies over the past 25 years. Statoil has installed almost 500 subsea wells contributing to 50% of Statoil’s production.
Statoil’s technology strategy identifies four business critical technologies and one of them is taking subsea processing colder, deeper, and longer. This includes putting more of the platform processing functionality subsea and realizing the “subsea factory” by 2020. Most of the main building blocks of the subsea factory (pumps, compressor, scrubbers, etc.) are already qualified or deployed in fields, but need to be simplified to reduce size and increase reliability.
Shell sees subsea evolution encom-pass-ing three main steps: pipelines and cables, trees and manifolds, and process-ing. Subsea processing is necessary because:
- The portfolio dictates it. In Shell’s portfolio, there are fields requiring 800 km multiphase transport.
- Subsea processing is required to open up new areas such as the Barents Sea and Alaska.
- New solutions are needed to develop solutions that are “out of sight.”
Subsea processing at Shell started with the Draugen Framo pump run by injection water in 1993. In the future, subsea systems will take the hub role from platforms. This will require more flexible solutions to tie back to subsea hubs, onshore facilities that can handle and operate more complex subsea technology, smarter ways to access the equipment in the middle of the winter, and a project organization prepared to perform technology development as part of the project.
When starting offshore oil and gas production, Shell employed people with onshore experience. This is the same now for subsea processing. At Shell, subsea experience is with the project execution department, although all parts of the operator’s organization need subsea experience to realize subsea solutions.
Petrobras has extensive subsea experience over the past 30 years. Its first subsea tree was installed in 1979 and today, the company has 800 wells, buying 100 trees per year. In addition, it has lots of experience with subsea ESPs.
Petrobras has 16 subsea ESPs, 16 mudline ESPs, one mudline ESP skid, and one Helico-axial multiphase pump. Among the challenges the company has faced are:
- Assets do not want to fund technology developments. When the assets realize they need the new technology, there is little time to develop the technology.
- Interfaces are too complex and there is a need for plug-and-play solutions.
- Too much topside equipment is needed. Installation of this makes a lot of disturbance to the ongoing production.
The opportunities for subsea processing as seen by Petrobras are:
- US Gulf of Mexico—subsea boosting (now)
- Campos Basin—subsea ESP, boosting, compact processing (2015–2018)
- Northeast Brazil—subsea boosting, compact processing, compression, power distribution (2020)
- Pre-salt—subsea boosting, compact processing (2018–2020)
For the Pazflor field development, Total and its partners have spent USD 9 billion to produce 590 million bbl of oil. Two-thirds of the reserves are being produced through gas/liquid separation.
Imagine if the separation equipment had failed—if the system had not been working perfectly from Day 1? This would have set the technology back for years. Hence, the major success criteria to keep subsea processing attractive to operators is to have equipment perform as expected.
Total has confidence in subsea processing and is looking at solutions with deployment from Day 1, not only as an improved oil recovery tool. The company sees benefit in applying subsea processing technologies for several field developments, mostly focused on boosting opportunities in South America and west Africa.
Total considers risk assessment at the time of investment decision to be very challenging. Rigorous assessment of the TRL to estimate risk and associated mitigating activities is important to persuade decision makers of the need for a project.
Looking to the Future
Key challenges for operators ahead include the need to:
- Increase recovery and accelerate production.
- Open up and expand into new and even more hostile environments.
- Focus on adding value to limit additional cost.
- Deal with supply chain resourcing constraints.
Other challenges remain. Often, few operators are willing to invest significantly and vendors are left to self-finance technology development, leading to a culture of defensiveness and secrecy and a high hardware price to cover R&D costs. In addition, intellectual property issues can stop collaboration and create single supplier markets, reducing operators’ commitment to apply technology
Increased collaboration is required to solve these issues. Collaboration on subsea processing is dysfunctional at present. Operators do not have resources to follow up and interface with vendors sufficiently. System engineering houses do not have sufficient verified test and operational data from vendors, which prevents the operators from building convincing business cases and focusing where technology qualification is required.