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This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders. Examples are provided including corporate, business unit and department case studies. Safety leadership focuses on the Human Factors (HF) which complement technical training to optimise reliability, safety, compliance, efficiency, and risks within a team-based environment. The IOGP laid down the HF skills and competencies required, and they form the basis for specialised O&G HF training's delivered by Mission Performance. This 1-day course reviews the key human factors but then also reviews what can be done to accelerate and scale operational roll-out for optimum and sustained impact, including integration with existing safety processes and (reporting) systems, refreshers, assessments, measurements, as well as the role of leadership and culture. Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion.
The first presentation will demonstrate how an integrated and systematic approach to predicting scaling potential was used to appropriately monitor and manage scale during unconventional production. The next case study will show how computational fluid dynamics modelling helped on the Nova Field to significantly improve scale inhibitor squeeze placement in an open hole horizontal with large reservoir pressure differences along the well, through the application of non-Newtonian fluids and inflow control devices. Finally, a study involving the comparison of carbonate scaling tendency and scavenging ability of six different H2S scavengers will show that chemistries are available that scavenge efficiently and do not increase carbonate scaling tendency.
World demand for energy is substantial and continues to grow. By 2020, it is expected that the world will need approximately 40% more energy than today, for a total of 300 million barrels of oil-equivalent energy every day. Meeting higher energy demands will require a portfolio of energy-generation options including but not limited to oil, natural gas, coal, nuclear, steam, hydro, biomass, solar and wind.
New horizons are being explored. Wells are drilled in greater water depths. Drilling units are continually upgraded to target deeper hydrocarbon-bearing zones. Wellbore tubular metallurgy is continually upgraded. Drilling, completion and stimulation fluids are being developed for extreme temperature and pressure environments.
As the preferred technology to enhance "oilfield" energy production, well stimulation has and will continue to have an important role in fulfilling the world's future energy needs. Well stimulation generally uses fluids to create or enlarge formation flow channels, thereby overcoming low permeability, as in "tight?? formations, and formation damage, which can occur in any formation type. A common and very successful stimulation option, matrix acidizing, utilizes acids that react to remove mineral phases restricting flow. Depending on the formation and acid type, flow is increased by removing pore-plugging material; or by creating new or enlarged flow paths through the natural pore system of the rock. However, higher-temperature environments present a challenge to matrix acidizing effectiveness. High temperatures can negatively affect stimulation fluid properties and certain acid reactions. Thus, careful fluid choice and treatment designs are critical to successful high-temperature matrix acidizing.
With proper fluid selection, design, and execution, matrix acidizing can be applied successfully to stimulate high-temperature oil & gas wells and geothermal wells. These types of wells have some common features, but they also have significant differences (e.g., completions, mineralogy, formation fluids and formation flow) that influence stimulation designs and fluid choices.
This paper summarizes best practices for designing matrix acidizing treatments and choosing stimulation fluids for high-temperature oil & gas wells and geothermal wells. Included are case histories from Central America. Lessons learned about differences and commonalities between stimulation practices in these well types are also discussed.
Flow assurance has been one of the major considerations in deepwater completion design, in which undesired heat loss from production tubing contributes to the formation of gas hydrates and causes the deposition of paraffin and asphaltene materials. Traditionally, controlling annular heat loss has been achieved with the injection of steam, the application of silicate foam, the pressurization of the annulus with inert gas, the use of gelled oil as an insulating packer fluid, and the use of vacuum insulated tubing (VIT). Each of these applications, however, has drawbacks because of either its working mechanism or the higher cost associated with the technology.
To secure the insulation of the wellbore and to reduce heat transfer from the production tubing to the surrounding areas, various aqueous insulating fluid systems with superior thermal properties have been developed in recent years. Field applications of these fluids have demonstrated significant reduction in heat loss by reducing conduction and minimizing convection. These thermal insulating fluids have been implemented with great success in more than 75 deepwater riser and packer applications in the Gulf of Mexico (GOM) over the last several years. Case histories have demonstrated that installation of these water-based insulating fluids is an effective alternative to conventional insulation options and is becoming the preferred insulation method in many deepwater projects.
This paper will highlight the evolution of different insulating fluid systems and the field experience with each system. Proper testing methods relevant to oilfield flow assurance will be discussed and testing results for these fluids will be detailed. Field cases in the GOM will be summarized, and the effectiveness of these fluid systems will be demonstrated.
Deepwater-oil and -gas exploration and development in the GOM has been a great success since the oil industry took the first step in the middle of 1990s. By the end of 2004, production from the deepwater fields in the GOM grew to an estimated 3.9 billion cubic feet of natural gas per day and 953,000 barrels of oil per day, which accounted for approximately 65% of the GOM oil production in 2004. The trend of exploration and development within the deepwater GOM shows no sign of diminishment, as evidenced by the 118 deepwater projects on production as of 2006 (U.S. Department of the Interior 2006). It has been forecast that the deepwater fields in the GOM would be producing nearly 2.0 million B/D in 2008.
As more multiphase hydrocarbons are produced from deepwater fields and transported for long distances, flow assurance becomes a more critical factor in the design stages of any oil- and gas-production system.
Flow assurance covers all issues related to the maintenance of the flow of oil and gas from reservoir to reception facilities. Being a multidiscipline activity, it involves the assessment of multiphase production systems and management of possible flow stoppages caused by the formation and deposition of solids. Prediction or modeling, prevention, and redemption of the formation of gas hydrate, paraffin, asphaltene, and scale buildup within the production tubing and flowlines are essential requirements.
The temperature in deepwater is usually near 40°F, or 4.4°C, which can cause flow problems in riser and export pipeline through undesired heat loss from production tubing by forming and depositing gas hydrate, paraffin, and asphaltene materials. Therefore, effective control of annular heat loss is critical to keep pipelines free of solid accumulations.