Today, almost half of Western Canada's natural-gas production comes from the Triassic-aged Montney formation, a sixfold increase over the last 10 years while gas production from most other plays has declined. In the last few years, demand for condensate as diluent for shipping bitumen has driven development of liquids-rich Montney natural gas leading to a surge in gas production and gas-on-gas competition in the Western Canadian Sedimentary Basin (WCSB), which has driven local natural gas prices down. This has had a material effect on the operations and finances of companies active in the Western Canada and is reshaping the Canadian gas industry. A significant portion of this growth has taken place in NE British Columbia and with the planned electrification of the industry in British Columbia, including the nascent LNG operations, will influence tomorrow's power industry in this region. NE British Columbia is a geographically large area with sparse population and the power supply into this region has lagged behind development of oil and natural gas resources. The area was originally served from geographically closer NW Alberta. More recently, supply was established from the BC Hydro power grid with the most significant developments being Dawson Creek-Chetwynd Area Transmission (DCAT) completed in 2016 and the additional 230 kV transmission projects scheduled for completion in 2021.
Mature heavy oilfields in the Northern Peruvian Jungle have produced oil for more than 40 years under primary recovery mechanisms (cold methods). As these fields are exploited by a strong water drive assisted with ESPs, total oil production has surpassed more than 1 billion barrels of oil with an average 15% primary recovery factor; ultimate recovery is expected to account for 17% at an economic limit of approximately 98% water cut. According to the
This study explores the development options (technical an economic) to produce heavy oil resources at commercial rates and showcases three optimization scenarios of higher recovery efficiency (additional 5%, 10% and 15% RF) utilizing current technology and sensitizing their economic variables with the main objective of increasing the net present value at the basin level. This is achieved by exploring and validating synergy strategies available in the basin and proposes investment for the Norperuano pipeline revamp to pump light oil/diluent to heavy oilfields (e.g Block 67) and make transportation of volumes currently classified as resources feasible. Lastly, this paper shows the current royalty framework in the Loreto region on a block basis and explores the financing alternatives to foster development and exploration activities in the North Peruvian Jungle heavy oilfields.
The workflow starts with identifying heavy oil development strategies, prioritizing and selecting the most appropriate technologies to optimize production performance and increase recovery efficiency; then, infrastructure options and financing alternatives are carefully reviewed to ensure heavy oil is produced with an appropriate amount of diluent. Finally, royalty and other tax incentives are suggested to ensure a profitable exploitation of heavy oil resources. Typically, primary recovery factors for heavy oilfields range between 10 to 15% with several alternatives for development such as multilateral drilling, steam flooding and HASD which would at least double production rates and increase recovery factors by 10% to 15%. Pilot tests of thermal recovery methods are strongly recommended for some fields in early development stage such as the Bartra field in Block 192 and the Raya and Paiche fields in Blocks 39 and 67 respectively. In order to handle new production rates, modifications to the Norperuano pipeline are proposed; additional in-situ loops and a parallel new pipeline are suggested, not only to ensure diluent/light oil transportation to supply the heavy oilfields, but also to increase transportation capacity of diluted oil to surface storage facilities and to the Refinery Complex in Talara; located on Peru's northern Pacific coast which is currently undergoing an expansion from 65,000 bopd to 95,000 bopd due by November 2020.
Assuming the first two conditions are met (the increase of production rates and recovery factors, and the egress constraint is no longer relevant) the profitability of the project at the basin roll-up level must be tested with a reserves model with inputs such as production rates by block, operating and capital expenditures for the different reserves/production wedges, royalty rates and taxes. The model must be consistent with the development program proposed by the operators in the region and be run at different pricing scenarios to stress-test the break-even value at several levels.
The recently held CERAWeek conference in Houston brought together top executives of the oil and gas industry and provided insight into the global and regional energy future by addressing key issues such as geopolitics, technology, and cyber risks. Two young professionals from the industry who participated in the event's Future Energy Leaders program share their takeaways with TWA. Just another conference I thought, but I was proven wrong. It was a gathering of the minds, the who's who in the energy industry, political leaders, and key influencers, and decision makers driving a global discussion on the current state of the industry and the future ahead. Each day focused on a different aspect of energy, whether it was about oil, gas, or power and transportation, all were tied by technology and the impact that has on each one.
We all identify the need to integrate climate change into corporate strategy, with a profitable Carbon Capture Utilisation & Storage (CCUS) business model the elusive goal. Today, CCUS forms 10% of the R&D program of Total, a founding contributor to the OGCI Climate Investments fund. Here in the North East of Scotland, UK and Scottish Governments, along with project developer Pale Blue Dot Energy and Total are providing match funding to the European Commission’s Connecting Europe Facilities fund to progress feasibility work on the Acorn CCS project. As society continues to drive an expectation beyond hydrocarbons, what proposal might the North East of Scotland offer in response?
To meet ambitious emissions reduction targets, the UK must envisage radical changes to the energy economy. Already affecting power generation, these changes must drive further into transport and domestic/industrial energy consumption. Two technologies which may play a part in the decarbonisation of the UK energy business are CCUS and the use of Hydrogen as an energy carrier and energy store, with several studies showing that clean hydrogen is potentially the lowest cost route to meeting UK emission targets in multiple sectors. This builds on the UK’s world class gas network infrastructure, which can be repurposed to avoid becoming stranded, avoiding the enormous expense of increasing the capacity of the electricity transmission network, much of which would lie idle during the summer. The UK gas network carries approximately three times more energy than the electricity network, at one third the unit cost to consumers, and meets winter peaks that are five times greater.
Different to previous CCUS projects, and having the Oil and Gas Authority (OGA)’s first carbon dioxide appraisal and storage licence award, ACORN is an opportunity to evaluate a brownfield CCUS solution to capture, transport and store post-combustion CO2, combined with an upside through emerging pre-combustion CO2 capture technology relating to the production and sale of bulk hydrogen produced from natural gas with a zero-emission target. Located at the St Fergus Gas Terminal – an active industrial site where around 35% of all the natural gas used in the UK comes onshore. ACORN is designed as a "low-cost", "low-risk" CCUS project, to be built quickly, taking advantage of existing oil and gas infrastructure and well understood offshore storage sites. The Acorn Hydrogen project undertakes to evaluate and develop an advanced reformation process which will deliver the most energy and cost-efficient industrial hydrogen production process whilst capturing and sequestering CO2 emissions. An initial phase offers a full-chain demonstration project, an essential step toward commissioning the concept and subsequent commercialisation of large-scale CCUS and Hydrogen deployment in the UK.
SPE Offshore Europe represents an ideal opportunity to update both the region and industry on results, observations, and conclusions with respect to the evolving development architecture, selected process technologies, Government and gas transportation regulatory engagement as this, the leading Scottish CCS project continues its journey toward a final investment decision.
This paper's focus is the advocation of utilising diagnostic data available from digital field devices to help reduce operating costs for end users.
In recent years companies across multiple industrial sectors have invested in improving their understanding of both the historical and live data they produce. The source of the data is specific to the processes but the objective for all remains the same - to use statistical techniques to develop a toolset that can be used to predict performance based on live and historical data.
For the oil and gas industry, the continued adoption of digital device transmitters has increased the volume of data available from instruments such as flow meters, temperature probes and pressure sensors. Typically, this additional data provides information on the integrity or quality of the associated device. However, with the appropriate level of facility and instrument knowledge it is also possible to infer information with respect to the process stream.
Furthermore, this data, if correctly interpreted, can be used to predict maintenance and calibration requirements, resulting in reduced staff effort and shutdowns. The need for physical intervention due to device failure is also reduced, which in turn minimises the potential for accidental hydrocarbon release when a device is removed for repair or replacement.
NEL are currently undertaking research projects with the primary objective of developing definitive correlations between process effects, meter condition and diagnostic data response. The paper provides details of said research, with particular reference to the data science and mathematical techniques currently being trialed for the analysis stage. The techniques, when fully developed, will be metering technology specific and therefore offer a level of insight to end users on facility and meter performance which is not currently available in industry. The toolsets developed will in turn provide the end users with the knowledge and confidence to make cost saving decisions with respect to planned maintenance as well as improving facility efficiency through a more comprehensive understanding of their own data sets.
The UK and the international community have an increasing interest in the benefits of a hydrogen-based economy. Existing and emerging technologies that are inherently carbon-neutral and potentially carbon-negative are increasingly attractive, given the challenge of meeting climate targets to prevent climate change and build a clean growth strategy. The integration of clean energy technologies across the UK Continental Shelf (UKCS) can increase the flexibility of the energy system, driving efficiency, cost reduction and enhancing the value of natural resources.
There are over 250 platforms and 45,000 kilometres of pipeline installed within the United Kingdom Continental Shelf (UKCS). As these assets near the end of their economic life oil and gas operators are planning to decommission these facilities in an efficient and cost-effective manner. Current cost forecasts for this activity exceed £58bn with approximately 50% borne by the operators and 50% borne by UK taxpayers.
The Hydrogen Offshore Production (HOP) project identifies an alternative to decommissioning by providing re-use options for offshore infrastructure while addressing the national challenge of a low carbon energy supply. In doing so, the project will prove the feasibility of several decentralised hydrogen generation, storage and distribution options that collectively provide a scalable offshore hydrogen production solution, whilst offsetting a portion of decommissioning costs that are currently forecast for all offshore assets and infrastructure.
HOP will tackle the challenge of bulk hydrogen production by (1) proposing viable environmental and economic technology solutions to be deployed offshore, (2) developing a new Industrial Hydrogen Production test site to both prove the industrial benefits and to aid commercialisation of emerging technology and, (3) conducting market analysis and producing the business case for the transformation of existing offshore infrastructure, re-purposing assets and demonstrating the viability for decentralised generation of hydrogen.
As part of the project, an Industrial Hydrogen Production test site will be established with Flotta (Orkney Islands) being proposed as the location. This will provide a test bed for technology, fast-tracking its development and providing a route for accelerated commercial deployment. Within a region of considerable renewable energy generation, the island of Flotta is ideally placed to benefit from local expertise, existing supply chain and advanced technology solutions. For example, the Industrial Hydrogen Production test site would greatly benefit from lessons learnt at the nearby Orkney Water Testing Centre.
This paper will discuss when it is advantageous (in the context of an offshore oil and gas environment) to process data at the network edge (in close proximity to equipment assets) or to stream data to a cloud-based Internet of Things (IoT) platform for analysis. It will offer an objective assessment of both approaches and provide recommendations for securing data in both cases, as part of an overarching cybersecurity strategy.
IoT has opened the door to significant efficiency gains in the oil and gas industry. This is particularly the case in the offshore sector, where there is a pressing need to reduce costs and maximize equipment availability. In some cases, it is advantageous to process data in close proximity to equipment assets (i.e., at the edge). In others, it makes more sense to securely stream data to a cloud- based IoT platform and harness artificial intelligence (AI) to aid in decision making. In certain cases, both architectures can be utilized in compliment to one another.
Many factors need to be taken into consideration when evaluating an edge or cloud-based approach. Some of these include data volume, transmission and processing speed, control of data, cost, etc. Edge computing can be used to streamline and enhance the efficiency of data analytics. In certain applications, this can mean the difference between analyzing a performance failure after the fact, and pre-empting it in the first place, which in the offshore environment could potentially translate into millions of dollars per day.
On the other hand, there are situations where it is beneficial to store large volumes of data on a cloud-based platform. For example, if the goal is to leverage advanced IoT-based industrial analytics to optimize an entire fleet of a certain type of equipment, the cloud may be the best solution. Cybersecurity is another consideration. Attacks on critical infrastructure have risen significantly over the course of the past year. As more Intelligent Electronic Devices (IEDs) are deployed in the oil and gas industry to optimize efficiency, Industrial Control Systems (ICSs) are increasingly vulnerable. As a result, the threat extends beyond proprietary data to mission-critical operational technology (OT) assets and equipment.
Cybersecurity standards and layered, defense-in-depth models have grown in response to the frequency and sophistication of cyber attacks. Additionally, recent advances in cyber defense technology incorporate small, kilobit-sized embedded software agents to monitor networks for anomalies that could signal an intrusion. This paper will explore new cybersecurity threats to oil and gas assets, as well as strategies operators can employ to defend against them, whether using an edge or cloud-based platform, or both.
The major challenge facing society in the 21st century is to improve the quality of life for all citizens in an egalitarian way, by providing sufficient food, shelter, energy and other resources for a healthy meaningful life, whilst at the same time decarbonizing anthropogenic activity to provide a safe global climate. This means limiting the temperature rise to below 2 C. Currently, spreading wealth and health across the globe is dependent on growing the GDP of all countries. This is driven by the use of energy, which until recently has mostly derived from fossil fuel, though a number of countries have shown a decoupling of GDP growth and greenhouse gas emissions from the energy sector through rapid increases in low carbon energy generation. Nevertheless, as low carbon energy technologies are implemented over the coming decades, fossil fuels will continue to have a vital role in providing energy to drive the global economy. Considering the current level of energy consumption and projected implementation rates of low carbon energy production, a considerable quantity of fossil fuels will still be used, and to avoid emissions of GHG, carbon capture and storage (CCS) on an industrial scale will be required. In addition, the IPCC estimate that large scale GHG removal from the atmosphere is required using technologies such as Bioenergy CCS to achieve climate safety. In this paper we estimate the amount of carbon dioxide that will have to be captured and stored, the storage volume and infrastructure required if we are to achieve both the energy consumption and GHG emission goals. By reference to the UK we conclude that the oil and gas production industry alone has the geological and engineering expertise and global reach to find the geological storage structures and build the facilities, pipelines and wells required. Here we consider why and how oil and gas companies will need to morph into hydrocarbon production and carbon dioxide storage enterprises, and thus be economically sustainable businesses in the long term, by diversifying in and developing this new industry.
The industry is well acquainted with domestic socio-political, regulatory, and product egress headwinds that hinder our ability to get product to market. Furthermore, there are several macroeconomic issues that are weighing on oil & gas such as carbon tax, peak oil, EVs and renewables. Focusing on headwinds reduces our abilities to find solutions, but are there tailwinds that exist that can allow us to mitigate some of these challenges? This panel discussion will focus on feedback from the broader capital markets, the potential opportunities in other industries that faced similar challenges, and what they did to overcome those challenges. As Montney producers continue to face challenging market conditions, the necessity persists for delivering capital efficient programs through the development of core acreage and multi-pad drilling.
In response to questions from lawmakers on whether federal law adequately provides for the prosecution of "criminal activity against infrastructure," the Department of Justice recently committed to "vigorously" prosecute those who damage "critical energy infrastructure in violation of federal law." Water management for upstream will transform over the next few years. In many cases, more-effective water management will only be possible with water infrastructure.