This challenging reservoir characterization case study is defined by the interaction between two reservoirs with different production mechanisms: a fractured basement reservoir and an overlying sandstone reservoir. The existing static geologic concept has been significantly enhanced by integrating pressure data from a unique three-year shut-in period to aid modeling of fractured reservoir connectivity. Previously, the seismic dataset was predominantly used to model the fault and fracture network and guide well planning. In the current approach, the full field data set, including all drilling parameters and new reservoir surveillance data were integrated to address uncertainty in the connected hydrocarbon volume and the relative importance of each production mechanism. The result is a reservoir management tool with which to test re-development concepts and effectively manage pressure decline and increasing gas/oil ratio (GOR) and water production.
To achieve a fully integrated history matched model, the first step was to make a thorough review of the existing detailed seismic interpretation, vintage production logging tool runs (PLT's), wireline logs (including borehole image logs (BHI)) and drilling data to find a causal link between hydraulically conductive fractures and well production behavior. In parallel, a material balance exercise was run to incorporate the new pressure data acquired during the field's shut-in period. The results of the material balance analysis were combined with seismic and well data to define the distribution of connected fractures across the field. Additionally, the material balance analysis was used to determine the connected hydrocarbon volume, the distribution of initial oil in-place and the relative hydrocarbon contribution from each production mechanism.
The field is covered by multi-azimuth 3D seismic and 43 vertical to highly deviated development wells, providing significant static and dynamic data for characterizing the distribution of connected fractures. Despite this high quality, diverse and field-wide dataset, prior modeling iterations struggled to sufficiently describe the production behavior seen at the well level. This has resulted in a major challenge to predicting the production behavior of new development wells and planning for reservoir management challenges. Capturing the complex interaction between production variables (including lithology, matrix versus fracture network, geomechanical stresses, reservoir damage and pressure depletion) at a field level instead of at an individual well level resulted in a unified static and dynamic model that reconciles all scales of observation.
This oilfield represents a unique reservoir characterization opportunity. The result is a key example of how iterative, integrated geological and engineering driven reservoir modeling can be used to inform the development in a complex, mature field. This case study provides an excellent analogue for the reservoir characterization of other fractured Basement fields and/or Basement-cover reservoir couplet fields in the early to late phases of their development.
The Health and Safety Executive's analysis shows poor hazard identification and risk analysis is a causal factor in 12 out of 14 recent major hydrocarbon releases, demonstrating that major accidents could be prevented if workers had a better understanding of major accident hazards (MAHs). Therefore, it is proposed that improving awareness of MAHs across the workforce, both onshore and offshore, would lead to better MAH management and a reduction in major accidents.
Once the domain of process engineers, major accident hazard management has been largely overlooked by much of industry. It was acknowledged as a problem but ignored in the hope that specialists had it under control.
Step Change in Safety's Major Accident Hazard Understanding workgroup responded to this by identifying different job roles (onshore and offshore), evaluating the resources to develop MAH understanding already available and creating a suite of resources to fill the gaps.
These resources include an e-learning tool for onshore (office-based) personnel, bowtie lunch and learn sessions, gap analysis tools to identify training requirements of offshore jobs, senior leaders' workshops and a MAH Awareness programme. The MAH Awareness programme, consisting of short films and presentations which can be customised to suit specific worksites and job roles. Each of the four packs explores different aspects of major accident management including MAH identification and analysis, bowties and safety and environmental critical elements, barrier maintenance, assurance and verification and the importance of taking responsibility of ‘owning’ your barrier.
Analysis of questionnaires completed before and after exposure to the programme demonstrates that knowledge of MAH management increased by approximately 30%. Additionally, the data demonstrates that elected safety representatives have a greater base knowledge of MAHs than the general offshore workforce, as do technical staff compared to non-technical and those employed by operators compared to contractor employees.
Whether this increased knowledge gained through taking part in the MAH Awareness programme is retained or impacts the number of major accidents has not yet been analysed but data such as the number of major accidents, including hydrocarbon releases, will be examined over forthcoming years to evaluate the effectiveness of the resources developed.
Innovation is critical to the future success of the oil and gas industry (
As a way of addressing this, the TechX programme at the Oil & Gas Technology Centre has launched TechX Ventures in July 2018 – a partnership with Deep Science Ventures (DSV) – that combines deep science with engineering to create the next generation of start-up companies with technologies that will position the oil and gas industry for a sustainable future in a low carbon economy.
The start of the programme was a workshop held with industry, academia and the scientific community, to identify areas where new thinking and technology could open up significant opportunities. Three challenge themes were developed, each of which became an opportunity areas for DSV to address. These are:
As part of the TechX Ventures programme, DSV recruited thirty scientists and engineering experts from across the world to tackle the opportunity areas and at the end of the nine-month programme a total of six new start-up companies with new intellectual property were created and invested in by DSV. Of these six, two were selected to join the coveted TechX Pioneer accelerator programme run by OGTC in Aberdeen. These companies are called Eltera and Optic Earth.
Tyrie, Jeb (Bridge Petroleum) | Mulcahy, Matt (Bridge Petroleum) | Leask, Robbie (Bridge Petroleum) | Wahid, Fazrie (Bridge Petroleum) | Arogundade, Olamide (Schlumberger) | Khattak, Iftikhar (Schlumberger) | Apena, Gani (Schlumberger) | Samy, Mohammed (Schlumberger) | Sagar, Rajiv (Schlumberger) | Xia, Tianxiang (TRACS International) | Nyadu, Kofi (WorleyParsons, Advision) | Maizeret, Pierre-David (Schlumberger)
This paper describes the proposed re-development of the Galapagos Field, comprising the abandoned NW Hutton field and the Darwin discovery (Block 211/27 UKCS) which forms a southerly extension. The paper covers the initial concept and analytical evaluation, the static uncertainty model build, the dynamic model history-match, the iterations between static and dynamic modelling, the development subsea and well locations, the optimisation workflow of the advanced Flow Control Valve (FCV) completions in both producers and injectors and the facilities constraints.
The redevelopment plan involved several multi-disciplinary teams. 20 years of production data from 52 wells were analysed to identify the production behaviour and confirm the significant target that provided the basis for the development concept selection. The full Brent sequence compartmentalised stochastic static model was based on reprocessed seismic plus 14 exploration and appraisal wells. Streamlines, uncertainty sensitivities and mostly good detective work honed a history match to RFT, BHP, PLT and oil and water production. P50, P90/P10 models were selected and over 100 FCVs optimised to deliver the profiles against an identified FSPO facilities’ constraints.
Over 1,000 static models were delivered consisting of sheet sands, incised valleys and channels in heterolithic facies overprinted by a depth trend with appropriate uncertainty ranges. The high well count gave a tight STOIIP probabilistic range of 790/883/937 million stb. The early RFTs illustrated extreme differential depletion between Brent zones and subzones of the Ness. To history-match these the dynamic model retained the static model definition in the Upper Ness to capture the thin but extensive shales. The early 18-month depletion and the late steady production-injection phases were simulated separately in prediction mode and matched the Production Analysis estimated ‘future’ production giving confidence to the history matched model. The initial concept development of 4 subsea-centres, to cover the large field area, with an injector in each compartment proved a robust selection. The horizontal wells increase PI where needed and mitigate internal faulting. The optimisation of the FCVs significantly increased oil production from all zones and drastically reduced water injection and production so that the identified FPSO modifications were relatively modest. The final First Stage Field Development Plan consists of 11 producers and 6 injectors across developed and undeveloped areas confirmed robust P50 reserves of 84 million boe.
Robust concept selection allowed for early identification of production units so that constraints and modifications could be accounted for within the economic model.
The Galapagos field re-development plan is an excellent example of how detailed static and fully history matched dynamic models can lay the foundations for new technology like the optimisation of the FCVs to access bypassed reserves using significantly smaller production units with reduced requirements for power, compression, gas lift, pumping pressure, injection and production. In short, they shrank the facilities.
As a result of the 2016 Paris agreement, the challenge of climate change and the imperative of moving to a low carbon economy has intensified. This challenge has been added to the traditional objectives of affordable and secure energy sources. These three criteria are the basis for the Energy Transition. Increasingly, investors, consumers and policy makers are looking to energy businesses to reflect all these criteria as the basis of their company culture and objectives.
This paper looks to explore opportunities for the UK oil and gas industry to further align itself with the drivers set out above and continue to promote investment into a sector that is key to delivering the Energy Transition:
Improved communication of carbon reduction and mitigation efforts at both a national and global level Increased collaborative efforts aimed at reducing emissions resulting from exploration and production offshore The potential for UKCS oil & gas companies’ involvement in carbon mitigation and storage
Improved communication of carbon reduction and mitigation efforts at both a national and global level
Increased collaborative efforts aimed at reducing emissions resulting from exploration and production offshore
The potential for UKCS oil & gas companies’ involvement in carbon mitigation and storage
Over recent years, the offshore UKCS oil and gas sector has focused on improving cost efficiency in its offshore operations. This implies a commitment to continuously improve environmental performance despite the challenges of doing so in a maturing oil and gas basin, where maximising economic recovery from fields requires greater effort. Notwithstanding these challenges, the overall long-term trends in environmental performance are improving as a result of efforts by the industry.
Moving forwards, the benefits of effective emissions management will continue to intensify, beyond the regulatory requirements of environmental protection, as a result of two key drivers:
To maintain investor and public confidence – reducing both the carbon footprint of operations and carbon intensity of products used by consumers, will help position companies for a lower carbon economy. The business case - EU ETS Phase IV is modelled to cost the sector £2.2 billion from 2021 to 2030 as the cost of allowances is projected to increase combined with the reduction in free allowances. Therefore, reducing emissions at installations will continue to be imperative for improved environment performance as well as the continued economic viability of the installation.
To maintain investor and public confidence – reducing both the carbon footprint of operations and carbon intensity of products used by consumers, will help position companies for a lower carbon economy.
The business case - EU ETS Phase IV is modelled to cost the sector £2.2 billion from 2021 to 2030 as the cost of allowances is projected to increase combined with the reduction in free allowances. Therefore, reducing emissions at installations will continue to be imperative for improved environment performance as well as the continued economic viability of the installation.
The sector must therefore continue to adapt to these ongoing fundamental changes that are taking place in energy supply more widely. As with any industry, businesses need to respond to shifting economic and societal demands and the consequent changes in energy needs. Hence, the effective management of emissions must proliferate through both operations (exploration, production and transportation of hydrocarbons), and use of the products delivered.
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.
Integration of time-lapse seismic data into dynamic reservoir model is an efficient process in calibrating reservoir parameters update. The choice of the metric which will measure the misfit between observed data and simulated model has a considerable effect on the history matching process, and then on the optimal ensemble model acquired. History matching using 4D seismic and production data simultaneously is still a challenge due to the nature of the two different type of data (time-series and maps or volumes based).
Conventionally, the formulation used for the misfit is least square, which is widely used for production data matching. Distance measurement based objective functions designed for 4D image comparison have been explored in recent years and has been proven to be reliable. This study explores history matching process by introducing a merged objective function, between the production and the 4D seismic data. The proposed approach in this paper is to make comparable this two type of data (well and seismic) in a unique objective function, which will be optimised, avoiding by then the question of weights. An adaptive evolutionary optimisation algorithm has been used for the history matching loop. Local and global reservoir parameters are perturbed in this process, which include porosity, permeability, net-to-gross, and fault transmissibility.
This production and seismic history matching has been applied on a UKCS field, it shows that a acceptalbe production data matching is achieved while honouring saturation information obtained from 4D seismic surveys.
The key challenges concerning heavy oil are not associated with finding reserves, but in extracting, producing and transporting heavy crudes. This is even more challenging given the new normal lower oil price. In this presentation, a case study will be presented showing the successful implementation of highly technical modelling techniques in brownfield heavy oil field developments (UKCS).
Infinity's flow assurance and process engineers have been involved in almost all of the heavy oil developments in the UK continental shelf. - Mariner (12-14°API) and Bressay (11°API), Kraken (14°API), Bentley (10-12°API) and Corona (16°API) are some of the examples worth noting.
In the last couple of years the Production Assurance team at infinity have been responsible for the pre-FEED and FEED stages of one of the most important heavy oil fields in the UKCS. Infinity have provided engineering support to several major E&P companies for their heavy oil developments. This paper focusses on the unusual rheological properties, variable Flow Assurance characteristics during production and the most recent modelling approaches to study the behaviour of these challenging fluids. These projects are particularly interesting as they combine the challenge of both heavy oil and brownfield developments.
Key issues for design of heavy oil fields and development of a safe/optimum operating philosophy are addressed and will be shared in this presentation such as: Modelling non-Newtonian fluids with very high viscosities (impact on line sizing); Oil/water dispersion and formation of a stable emulsion; Selection of an artificial lift option and their respective impacts on the behaviour of the system (focus on HSP technology); Operational issues including relatively high restart pressures following an unplanned shutdown (gel formation).
Modelling non-Newtonian fluids with very high viscosities (impact on line sizing);
Oil/water dispersion and formation of a stable emulsion;
Selection of an artificial lift option and their respective impacts on the behaviour of the system (focus on HSP technology);
Operational issues including relatively high restart pressures following an unplanned shutdown (gel formation).
The key challenges with modelling heavy oil were developed and a novel approach to simulation and data benchmarking was developed in order to solve the classic heavy oil modelling issues. As an example, the relationship between shear rate and shear stress in difficult fluids that deviate from the classic Newtonian behaviour demands a very close relationship between the flow assurance engineers modelling the system and the fluid lab experiments required to benchmark the models.
Fred Ng is general manager of engineering at Wild Well Control, Inc. He has over 30 years of worldwide experience in operational, technical and management responsibilities for major and independent operators in the petroleum industry. He served extensive assignments covering land and offshore drilling operations in the Gulf Coast, Alaska, Texas, Indonesia, Malaysia, China, New Zealand and Ghana. Fred is a mechanical engineer by training, and holds a BS (Honors first class) from University of New South Wales (Australia), and MS and PhD from Texas A&M. He has taught in mechanical as well as petroleum engineering at University of Houston.
In the United Kingdom Continental Shelf (UKCS), a significant heavy oil prize of 9 billion barrels has been previously identified, but not fully developed. In the shallow unconsolidated Eocene reservoirs of Quads3 and 9, just under 3 billion barrels lie in the discovered, but undeveloped fields, of Bentley and Bressay. Discovered in the 1970s, they remain undeveloped due to the various technology challenges associated with heavy oil offshore and the presence of a basal aquifer. The Eocene reservoirs represent significant challenges to recovery due to the unconsolidated nature of the hydrocarbon bearing layers. The traditional view has been that such a nature represents a risk to successful recovery due to sand mobility; reservoir and near wellbore compaction; wormhole formation; and injectivity issues.
We propose improving the ultimate oil recovery by a combination of aquifer water production and compaction drive. By interpreting public domain data from well logs, the range of geomechanical properties of Eocene sands have been determined. A novel approach to producing the heavy oil unconsolidated reservoirs of the UKCS is proposed by producing the aquifer via dedicated water producers situated close to the oil-water contact. The location was determined by sensitivity analysis of water producer location and production rates. By locating water producers at the OWC with a production rate of 20,000 bbls/day of fluids, the incremental recovery at the end of simulation is increased by 4.1% OOIP of the total modelrelative to the ‘no aquifer production’, casesuggesting a significant increase in recovery can be achieved by producing the aquifer. A rate of 30,000 bbld/day located at the OWC was found to increase incremental recovery by 5.8 %OOIP relative to the ‘no aquifer case’. In all cases, as the reservoir fluid pressure is reduced, oil recovery increases via compaction and reduced water influx into the oil leg. This reduced pressure leads to a higher tendency towards reservoir compaction which is expressed as a change in mean effective stress and porosity reduction.