Cramer, Ron (Shell Global Solutions) | Mehrotra, Shailendra (Shell) | Goh, Keat-Choon (Shell Global Solutions Intl BV) | Steover, Matt (Shell Global Solutions US Inc) | Berendschot, Leo F. (Shell Global Solutions)
Downstream Refineries and Chemical Plants have benefited from real time optimization systems (RTO) for the last 30 years. Downstream RTO is a well established and permanent fixture in many plants - the "way we do things'round here!". Upstream E&P operations have "come to this party" much more recently and are using RTO more sparingly, even though the economic and HSSE benefits can be very significant. There are key differences between downstream and upstream. For example, downstream facilities do not deal with subsurface uncertainties, multiphase flow and isolated/harsh environments; while upstream operations do not usually have to deal with complex chemical processes. Integrated Oil Companies run upstream and downstream operations and integration of tools/practices across both regimes is often perceived to be of significant value. Hence, the purpose of this paper is to compare and contrast downstream and upstream RTO learnings with a view to identifying and describing: - similarities in production unit operations e.g.
Shepherd, Andrew G. (Nederlandse Aardolie Maatschappij BV) | van Dijk, Menno (Shell Global Solutions Intl BV) | Koot, Wouter (Shell Global Solutions) | Dubey, Sheila Teresa (Shell Global Solutions) | Poteau, Sandrine (Shell) | Zabaras, George John (Shell Global Solutions) | Grutters, Mark (Shell)
This paper presents an overview of the different flow assurance issues associated with naphthenic acids. In field development projects a good understanding of naphthenic acid phase behavior is essential to avoid unplanned plant changes and deferment. Good data on naphthenic acid content and speciation is obtained by using a representative sample. Basic measurements (e.g. TAN) are not sufficient to obtain a detailed understanding of the flow assurance issues regarding a particular crude oil. Infrared spectroscopy and mass spectrometry, high and low resolution, are the preferred tools for analysis of crude oils. The target naphthenic acid species, e.g. ARN or fatty acids will dictate the best suited method selected for analysis. Geochemical analysis of crude oils has helped to highlight some common features which can be used for prediction purposes. For bound soap scale-forming crude oils, a large amount of complexed acids result in emulsions which are difficult to break. Chemical treatments are needed and these should be identified early in the project stages. For soap scale-forming crude oils chemical treatment requires in depth analysis of topsides equipment and impact on existing chemical portfolio. Surveillance of soap scale-forming crude oils is possible using readily available equipment. For soap emulsion-forming crude oils, paraffin precipitation adds to the stability of the emulsion formed. Chemical treatment and heat is required for best results. Use of stock tank sample properties can be used for predictions regarding the type of naphthenic acid issue to be expected for particular crude oil sets.
Naphthenic acids play an important role in upstream and downstream oilfield activities in many diverse areas such as exploration geochemistry and corrosion. In E&P field developments within the discipline of flow assurance, the effects of naphthenic acids in crudes and condensate systems have been specifically reported in emulsion stabilization, formation of soaps, enhanced oil recovery performance and in natural hydrate inhibition1-5. The impact of naphthenic acids on facilities design cannot be underestimated. Most issues are treated with chemical solutions, and this affects CAPEX as well as OPEX. Thus there should be robust protocols to ensure naphthenic acids are correctly identified in conjunction with the other reservoir fluid properties as early as possible. By taking these steps, costly retrofitting or plant changes and deferment can be avoided. This work will review lessons learned to better understand the properties of naphthenic acids systems and their flow assurance impact. This will include a discussion on different related case histories. It should be mentioned that the impact of naphthenic acids should be studied on a field by field basis with a fit for purpose approach.
Suijkerbuijk, Bart (Shell) | Hofman, Jan (Shell Intl. E&P BV) | Ligthelm, Dick Jacob (Shell Intl. E&P BV) | Romanuka, Julija (Shell Global Solutions Intl BV) | Brussee, Niels (Shell Intl. E&P BV) | van der Linde, Hilbert (Shell Intl. E&P BV) | Marcelis, Fons (Shell International Exploration and Production B.V.)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the Eighteenth SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 14-18 April 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Improved oil recovery by low salinity waterflooding (LSF) represents an attractive emerging oil recovery technology, as it is relatively easy to implement and low-cost compared to other Improved and Enhanced Oil Recovery (IOR and EOR, respectively) processes. Even though LSF leads to extra oil recovery in most laboratory experiments and some promising data from the field have been presented, the mechanism underlying LSF is still unclear. Therefore it is difficult to predict a favorable performance of LSF in one field a priori, while dismissing others. This paper describes a series of spontaneous imbibition experiments on Berea outcrop core plugs, and some reservoir rock core plugs, that were designed to determine the impact of formation water, imbibing water and crude oil composition on wettability and on wettability modification by LSF. The data presented in this paper lead us to conclude that: - Spontaneous imbibition experiments with formation brine and low salinity brine executed on Berea outcrop material aged with a crude oil show excellent reproducibility; - An increasing concentration of divalent cations in the formation brine makes a Crude Oil/Brine/Rock system more oil-wet; - The extent of wettability modification towards more oil-wet upon aging also depends on the types of cations in the formation brine; - Improved oil recovery by exposure of the aged plugs to NaCl brines occurred when the imbibing phase was either higher or lower in salinity than the formation brine; - Aging of the same brine/rock system with different crudes having diverse physicochemical properties led to: o A spread in wettabilities after aging o A crude oil-dependent low salinity effect These results are discussed within the context of several mechanisms that have been put forward previously as an explanation for the low salinity effect. Introduction Low salinity waterflooding (LSF) is an IOR technique that can increase oil production from a reservoir through lowering the salinity of the injection water.
Romanuka, Julija (Shell Global Solutions Intl BV) | Hofman, Jan (Shell Intl. E&P BV) | Ligthelm, Dick Jacob (Shell Intl. E&P BV) | Suijkerbuijk, Bart (Shell) | Marcelis, Fons (Shell International Exploration and Production B.V.) | Oedai, Sjaam (Shell Intl. E&P BV) | Brussee, Niels (Shell Intl. E&P BV) | van der Linde, Hilbert (University of Stavanger) | Aksulu, Hakan (U. of Stavanger) | Austad, Tor
Modifying the chemistry of injection water yields improved wettability behavior on carbonate rock surfaces. Previous work has focused on demonstrating the effect of modified brine formulation on particular carbonate samples. Here the results of a more general screening study consisting of Amott spontaneous imbibition experiments on the samples from oil-bearing zones and from outcrops of different carbonate formations are reported.
Tertiary incremental oil production due to increased water-wetness was observed upon transition to brine of lower ionic strength. Additional oil recovery from the spontaneous imbibition tests ranged from 4 to 20% of OIIP (Oil Initially In Place), reflecting a large variability in the response and indicating a high complexity of the mechanism(s). Consistent with numerous published reports, Stevns Klint outcrop chalk samples were a clear exception and exhibited increased oil recovery with increasing sulfate ion concentration. These did not respond to lowering the salinity of the imbibing brine. Tertiary oil recovery from samples containing evaporites occurred simultaneously with dissolution of salt minerals, as evident from brine analysis. However, incremental oil recovery in the same range was measured for samples without evaporites but from the same geological formation. Hence, mineral dissolution as a mechanism for enhanced oil recovery could not be confirmed.
The results show that injection of low salinity brine into carbonate reservoirs has potential as an EOR technology. However, additional research is needed to improve the understanding of the underlying chemical and physical mechanisms and improve a priori predictability.
Zijlstra, Ellen Bertina (Petroleum Development Oman) | Riethmuller, Gael (Petroleum Development Oman) | Schaeftlein, Susanne (Petroleum Development Oman) | Al Mahruqi, Salima Saif (Petroleum Development Oman) | Naamani, Ali (Petroleum Development Oman) | Wolters, Frank Leonce (Shell Global Solutions Intl BV)
Klaver, Theo C. (Shell Global Solutions Intl BV)
Shell Global Solutions International B.V ("Shell??) has been involved for many years in the development of new technologies to separate CO2 and H2S from highly contaminated natural gas streams. This program has been significantly accelerated in recent years and major milestones have been achieved. The program focuses on technology solutions that are critical to develop (stranded) contaminated hydrocarbon gas and oil fields.
Several key technical challenges in the development of highly contaminated gas & oil fields have been overcome with new technologies developed by Shell. These challenges include: contaminant separation at minimal energy consumption and losses at minimum capital investment.
This paper will present these challenges and introduce new technologies that can help to reduce project development cost by as much as 40% compared to conventional technologies
External studies (Steiner, 2005) estimate a global (recoverable) resource of some 500 B boe (= 3000 tcf), as per bar chart figure 3 below, of gas that is ‘contaminated' by the previously defined levels H2S and/or CO2. These resources will require specific technologies to develop these fields economically. The bulk of these resources are in the Middle East, Canada, CIS, Asia and Australia. In general, one could say that the predominantly H2S contaminated fields can be found in the northern Americas (Canada), the Middle East (Abu Dhabi, Kuwait, Oman, Saudi Arabia, Qatar), and the Caspian regions (Kazakhstan, Russia). The indicated size exclude resources that could be accessed via H2S / CO2 Enhanced Oil Recovery (EOR).
The application of the newly developed technologies will be in the area of contaminated gas fields. With new technologies highly, contaminated gas fields can be economically developed to remove the contaminants from the hydrocarbon gas and re-injection of the contaminants. Since conventional technologies become less economic at increasing percentages of contaminant, the new technologies are specifically targeted at high concentrations of contaminants (>30%). The new technologies aim for efficiencies above 85 %, where efficiency is expressed as a percentage of hydrocarbon sales gas divided by the hydrocarbon feed stream. (Losses are due to fuel gas and hydrocarbons left in the contaminant stream)
The fast growing world demand for clean and affordable energy translates into a large demand for LNG production capacity in the next decade. To meet this rapid increase in production capacity, increasingly larger train sizes have become the trend for many years in order to benefit from economies of scale. In addition, large LNG projects reduce the specific engineering contractor efforts.
This paper presents a mega train design for a production of well over 10 Mtpa. The design is based on Shell's Parallel Mixed Refrigerant process. A large part of the expansion in world LNG production is currently taking place in the Middle East. Hence, a typical feed-gas composition from this region has been selected as the basis for integration of gas conditioning (treating), NGL extraction, liquefaction process, and utility facilities. The design will be flexible to meet the typical US low heating value requirement or higher values.
A combination of large mechanical gas turbine drivers and steam turbine drivers provide the refrigeration power demand. A plant-wide integration of heat generation and demand is provided by steam. This includes the waste heat recovery from the gas-turbine drivers, co-firing, the heat demand of the energy intensive treating train and heat production by the sulphur-recovery unit. The full utilisation of waste heat from the gas-turbine exhausts causes a step-change in plant efficiency and can help to reduce the specific CO2 emissions considerably with respect to a conventional LNG plant design, at the same time providing world class LNG train capacities without major step-outs in equipment.
Other challenges addressed in this paper are, maintaining the economy of scale for mega train designs, availability, operability, and start-up considerations for this highly integrated design.
Figure 1. Construction of the Sakhalin LNG plant.
At Shell, we see demand for natural gas growing by some 3% a year over the next 15 years, with demand for liquefied natural gas growing by some 8-10% a year . This is a mere consequence of the fast growing world demand for clean and affordable energy for which LNG is in many cases the preferred route. Already for a few years we have seen a large number of projects underway resulting in a constrained contractor market, a worldwide heavy demand for raw materials as well as issues around logistics of work force and products. These challenges call for large trains, particularly where large resources are involved as in the Middle East, Russia and Australia.
Shell and others have already increased train sizes in recent decades from 1 Mtpa to 8 Mtpa, primarily driven by the desire to reduce capital expenditure. Application of large trains will also help to use the available contractor capability more effectively.
Klaver, Theo C. (Shell Global Solutions Intl BV)
The Royal Dutch Shell Group (Shell) was one of the first energy companies to acknowledge the threat of climate change - to call for action by governments; our industry and energy users; and to take action ourselves. Shell's strategy: to expand our alternative energies portfolio, while investing in advanced CO2 solutions in order to improve our ability to manage emissions from our hydrocarbon business. Measures to manage future emissions will include developing new technologies to capture and store CO2 underground. The pursuit of Carbon Capture and Storage (CCS) technologies allows Shell to play an important and leading role towards addressing the need for an increasing worldwide demand for energy, while at the same time dealing with the need to reduce global emissions.
No single universal policy or technology will solve the CO2 challenge. Therefore, various CCS solutions will need to be considered within a portfolio of measures to reduce global CO2 emissions while assisting a transition towards a low-carbon energy future. Shell seeks to position itself as part of the solution to the climate change issue.
The United Nations Intergovernmental Panel on Climate Change (IPCC) has identified CO2 capture and storage (CCS) as the most promising for the rapid reduction of global emissions - by up to 55% by 2100. As the bridge to a more sustainable energy system, it is therefore a key solution for combating climate change - among a portfolio of solutions, including renewable energies, energy efficiency and biofuels
In order to achieve deeper reductions in CO2 emissions there will need to be new technologies brought to the market to enable a ‘Kyoto 2' type-agreement. Authorities such as the International Energy Agency, the European Union Commission for Research and the US Department of Energy predict that new technologies will include hydrogen fuels cells, clean coal technology, and storage of CO2 below ground - in deep saline formations or redundant reservoirs, or for enhanced oil recovery. Considerable attention is being focused on CO2 storage with the desire to reduce the cost of capture and storage below 25 $/t CO2.
Shell has a special team working on the CO2 Capture Project (CCP) Joint Industry Project. For the CCP Shell carries out studies, manages projects and the team is involved evaluating opportunities for deployment of the technologies within Shell. Shell also provides the Vice Chairman for this initiative and has several key-players working on this project. CCP is an international collaboration among industry, governments, academics and environmental interest groups focused on developing technology for CO2 capture and geological storage. The CO2 Capture Team (CCT) conducts Shell's participation in the CO2 Capture Project (CCP) and other external programs. CCT also works internally to apply external learnings and technologies within Shell businesses. Additionally, Shell's research and development funds and manages a separate CO2 storage program. Our goals are to:
In conventional practice, individual well oil, gas and water production is only measured on a weekly or monthly basis using shared well test facilities. Oil and gas production from a cluster of wells is hence difficult to manage, leading to late diagnosis of production problems and slow and conservative handling of production constraints. FieldWare Production Universe (FW PU) is a software application developed by Shell International Exploration & Production and Shell Global Solutions International that provides continuous real time estimates of well-by-well oil, water and gas production. FieldWare PU estimates are based on data driven models constructed and updated from production well tests and real time production data.
This paper will discuss two extensions of FieldWare PU data driven techniques. The first extension is to apply the data driven models for production optimization. The second extension is the case where no shared test facility for well-by-well production testing is available, and wells can only be tracked by monitoring changes in commingled production flows.
For the optimization functionality, the FieldWare PU data driven well models allow the prediction of the changes to overall and individual well production as a result of changes to individual well production chokes, lift-gas rates or other similar set-points. Well setpoints are then computed for optimizing oil and gas production subject to various well and overall production constraints.
Data driven techniques for well characterization using commingled production data will be illustrated in three particular production estimation scenarios: (1) individual well production with no shared well testing facility, (2) production from multiple subsea wells sharing a single tie-back pipeline, and (3) production from individual subsurface zones of a multi-zonal extended reach Smart Well.
FieldWare Production Universe
FieldWare Production Universe (FW PU) is a data driven modelling application developed by Shell to address fundamental gaps in the management and surveillance of oil and gas production operations. The development background and early operational experience of FW PU within the Shell Group are described in Poulisse et al.  and Cramer et al. . Using data driven models, FW PU essentially provides a "virtual?? three phase meter for each well. Earlier references to the potential use of virtual meters includes, for example, van der Geest , which is based on physical models. A brief reference to using data driven models for virtual metering, albeit using a less structured neural network approach, is given in Oberwinkler et al. . A recent paper that touches on the potential for data driven modelling is  by Stone.
Well three phase oil, water and gas production is conventionally measured via the periodic routing of the well to a shared test separator, the "production well testing?? process. The duration of the test is normally 6 - 24 hours or longer; the test frequency can vary but is typically weekly, monthly or even less frequent. The usual result of a well test is a set of spot readings and totalized or averaged numbers such as oil production rate, watercut gas-oil-ratio and tubing head pressure. The production of a well is then assumed to be uniformly at the tested production rates between well tests, other then at various intervals when the well is designated to be "closed-in". Sub-normal production rates, unstable production or increases in gas or water production are typically not detected until the next well test. Historically, there have been a number of approaches using well physical models combined with real time wellhead pressures and temperatures to predict 3-phase flow in real time or near real time. In practice, well physical models were found to be difficult to set-up, calibrate and maintain in an operating environment.
In an age where there is increasing concern for safety and the environment, why is there such interest in developing gas resources contaminated with high concentrations of H2S and CO2? This paper traces the history of contaminated gas production and explores the reasons why it has now become a focus for many countries.
The paper also addresses the significant technical, commercial and safety challenges that face developments of contaminated gas fields. In many cases, fields with high CO2 contamination cannot be developed economically without the introduction of new technology to both reduce costs and the amount of energy required to separate CO2 from methane, and then sequester it safely below ground.
For H2S contaminated gas fields, the challenges appear even greater. The extreme corrosiveness and toxicity of H2S requires the application of state-of-the art technology and operating procedures. There is simply no room for mistakes. sulfur management is also an issue that requires new approaches as planned developments will double globally traded volumes over the next ten year. The paper will outline the advantages and disadvantages of disposal options from blocking, Acid Gas Injection (AGI) and the application of new sulfur products such as sulfur cement (which is resistive to corrosive environments), enhanced asphalt (for hardwearing road applications) and sulfur fertilizer (with 15% greater yields). Indeed, the application of new sulfur technology has the potential to turn a global surplus of sulfur into valuable new products.
With many hundreds of tcf of contaminated gas resources worldwide, there is no doubt the industry will rise to the challenge and develop these resources in an economic and safe manner. But it will require the application of radical new technology and an integrated approach across the full value chain. It won't be for the faint hearted.
The volume of hydrocarbons discovered over the last 100 years shows a golden age in the 1960s and 1970s where over 600 Bln bbloe were discovered in the decades (see Fig. 1). During this time, many of the more difficult hydrocarbon discoveries were put to one side for later consideration. However, the progressive decline in new discoveries indicates that many of the world's major hydrocarbon basins have been discovered, and it is now getting progressively more difficult to find new and easy forms of conventional resources (see Fig. 2).
Fig. 1 Reserves addition per decade. Also indicated are some significant sour gas finds.
With demand continuing to increase, there is now a need to consider more difficult resources and hence more ‘expensive to produce' resources. These disadvantaged resources can be categorized as follows: (1) remote (far away from the market, no existing infrastructure), (2) harsh conditions (artic), (3) difficult reservoirs (ultra deep, tight formations) and (4) unfavorable composition (heavy oil).
Contaminated gas fields are typically part of that last category. As reported elsewhere in literature, there is at least 350 tcf of natural gas in place with 10 % H2S or more, and 700 tcf with 10 % CO2 or more. This is roughly 15 % of the total gas still to be produced. The bulk of these resources can be found in the Middle East, the Caspian region, and the Far East. Considering less severe levels of contamination, even up to about 40 % of the total gas still to be produced can be labeled as contaminated gas. Obviously, these numbers are large enough to attract the attention of a wide range interested entities, from IOCs and NOCs to innovation centers like universities.