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Kamel Ben-Naceur is CEO of Nomadia Energy Consulting, where he advises on sustainable energy policies and global/regional energy economics and outlooks. He has worked as a chief economist for a major oil and gas company and oilfield services company. Ben-Naceur has also worked as a director of the International Energy Agency and as an energy minister for the Tunisian government. He has chaired several SPE global committees, including Business Management and Leadership, the International Forum Series, and CO2 Capture and Storage. He has also taught several SPE courses on global energy, and strategic thinking and planning.
Tertiary shoreface-deltaic sediments in Brunei fields show different boomerang motifs on neutron-density and gamma ray-resistivity crossplots. A boomerang workflow named after the motifs is tested by calibrating to core data to quantify net/gross ratio and porosities under variable shale and hydrocarbon effects. The inflection between the two boomerang limbs marks the boundary between shoreface sandstones and offshore shale-type lithologies. Compared with subjective Vsh cutoffs, boomerang inflections are more objectively defendable signatures defining net and non-net rocks. Thin beds and heterolithic sandstones in lower shoreface and tidal environments are mixed in the sandstone limb near boomerang inflection. By including the thin beds and heterolithic reservoirs that are cut off by the Vsh approach, the static hydrocarbon in place in the studied fields increases by 10 to 40% based on the well data.
The shale matrix effect on porosity estimation in shaly heterolithic sandstones is resolved by interactively derived shale-line slopes without involving the uncertain clay volumes or clay parameters. Particularly, effective porosity, ϕEF, is estimated by inputting a wet-shale-line slope, ksh,, based on the shale limb on the neutron-density crossplot in each boomerang interval; it changes with depth as result of different compactions. Total porosity, ϕTOT, is estimated by a dry-shale-line slope; it is constant for most of the reservoirs based on core calibrations in the studied fields due to identical sediment provenance.
Hydrocarbon effect is independent of shale matrix effect, although they are mixed in the log responses. Hydrocarbon effect is qualitatively analyzed based on the angular rotation of the hydrocarbon-bearing sandstone limbs towards different fluid points. It is also quantitatively evaluated by the apparent fluid neutron-density parameters (φfl, ρfl) interactively determined by coherent ϕEF and ϕTOT estimations in a dual-porosity and dual-fluid model. For example, the calculated ϕTOT is significantly less than ϕEF if water parameters are used for gas-charged sandstones. By decreasing the (φfl, ρfl) from water (1, 1) until (ϕTOT – ϕEF) ≥ 0, we find the resultant ϕTOT matches with core porosity (except in unresolved thin beds); this is tested in more than 1,000 meters of cores in several fields covering a large range of lithology and hydrocarbon types. If invasion is insignificant, the resultant fluid density, ρfl, also matches with produced hydrocarbons. Therefore, the workflow not only provides coherent ϕEF and ϕTOT estimation in the rocks with variable shale and hydrocarbon effects but also the apparent fluid density profiles for hydrocarbon typing.
Mohe Basin Qilian Mountain Permafrost Qinghai-Tibet Plateau Cored gas-hydrate samples None Gas hydrate found in 13 wells None (Li et al. 2017) Origin of gas hydrate Thermogenic and biogenic Mainly thermogenic Coal derived (Liu et al. 2015) (Wang et al. 2015)(Li et al. 2017)
Bahrami, Esmaeil (Mehran Engineering and Well Services Co.) | Seyednia, Mahbod (Mehran Engineering and Well Services Co.) | Mosallaie Barzoki, Ali Akbar (Mehran Engineering and Well Services Co.) | Zangenehvar, Alireza (Mehran Engineering and Well Services Co.) | Rabbani, Seyedebrahim (Mehran Engineering and Well Services Co.)
Ship collision with offshore platform is one of the rare events in oil and gas industry and generally associates with huge physical and financial damage. An oil tanker collided with a jacket in the South Pars gas field and caused tough conditions for the operator to restore the jacket and wells to their original state. The crucial stages after the accident were killing a perforated well, wreck removal and cutting the wells below the section they had been bent or distorted and finally the wells abandonment by cementing coiled tubing operation on a dynamic positioning barge.
This paper focus on engineering design of a platform for coiled tubing injector head and pressure control equipment on the barge as well as finding a way that coiled tubing string pass through the gap between the platform and the underwater cut point of wells. For this purpose, a deck was proposed to build on the barge having a heavy duty flexible steel pipe extended from the deck to inside the wells cut point.
Various measures should be implemented to design this structure in order to have an operational safe method. The structure had to have sufficient strength to resist the forces applied on it especially during the operation in the predominant weather condition of Persian Gulf in the monsoon season. Therefore, a comprehensive study was conducted to determine stresses applied on the structure subjected to different types of wave velocities using finite element method.
The engineering design and simulation led to construct the proposed deck extending over the port side of the barge and elevating between the main deck and mezzanine deck with a long 4" flexible steel pipe at its bottom. In order to verify the engineering design and simulation before the operation, the structure load tested up to 40 metric tons.
This paper will peer over the challengeable engineering design of the deck for coiled tubing well abandonment under the condition of insufficient offshore facility.
The United Kingdom Continental Shelf (UKCS) is a very mature hydrocarbon basin, and it is currently beginning to experience the full complexity associated with decommissioning. The UKCS region is also subjected to what most would acknowledge is the most developed set of regional arrangements in the shape of Convention for the Protection of the Marine Environment of the North-East Atlantic (OSPAR).
Notwithstanding the degree of regional agreement in relation to decommissioning, an emergent insight from the current study in the UKCS is that there are significant issues that remain unresolved, which can be categorized into four main categories: Uncertainties of Regulatory Responsibilities Issues Related to Cross Boundary Operations Issues Regarding Long Term Liability Commercial Issues Across Boundaries
Uncertainties of Regulatory Responsibilities
Issues Related to Cross Boundary Operations
Issues Regarding Long Term Liability
Commercial Issues Across Boundaries
This finding has implications for other parts of the world that will have to face the challenges of decommissioning in the coming years, especially where they have not yet developed regional arrangements. Perhaps most challenging in this last regard will be the South China Sea given its history of contested island and maritime claims among several sovereign states within the region (
In comparison with the North Sea, the geographical make-up of the South China Sea is much more complicated and there are many more countries sharing maritime borders in the region, making these potential offshore decommissioning issues more likely to occur. It is thus important for a regional offshore decommissioning agreement to be in placed in the South China Sea region to act both as a guideline and a dispute resolution mechanism in an event that disputes were to occur during offshore decommissioning operations.
This paper will highlight the 4 emerging areas of concern (as mentioned above) in offshore decommissioning in the UKCS to suggests that the countries in the South China Sea region could usefully have these in mind as they move to develop regional decommissioning arrangements. Primary qualitative data obtained from the semi-structured interviews will be used in this paper to highlight the concerns on offshore decommissioning in the UKCS while secondary data and literature will be used to link the 2 regions together to demonstrate the need for a consideration of a development of a regional decommissioning agreement in the South China Sea region.
Electrical Submersible pumps (ESPs) have been installed on a large scale for the first time in offshore Brunei. Despite having produced in Brunei for 80 years the company previously only had a single ESP running, and that was in an onshore field. The primary lift method in Brunei has been gas-lift, and regionally ESPs have not been widely adopted. As ESPs were relatively novel to offshore operations a steep learning curve was expected. Poor operation practices are a threat to run life, and failures are costly (especially offshore). This paper outlines the challenges faced by the project team, and the approach taken to execute this project successfully and operate ESPs smoothly from day one.
The application for these ESPs was relatively simple, with benign environments in low temperatures and shallow setting depths. The primary challenge with introducing ESPs to offshore Brunei was developing people, and building capability and hands on experience. The main approaches for this included: Building a new ESP operations team. Learning from other assets in the company portfolio (including in the Middle East and Western Siberia) via official visits, and sending staff for short term assignments. Developing long term vendor relationship including field operations support onshore and offshore. Rolling out an ESP competency plan with a clear outline on the required competency level for all personnel and how it could be achieved. Hosting more engagement sessions closer to first oil between the operations team and project team.
Building a new ESP operations team.
Learning from other assets in the company portfolio (including in the Middle East and Western Siberia) via official visits, and sending staff for short term assignments.
Developing long term vendor relationship including field operations support onshore and offshore.
Rolling out an ESP competency plan with a clear outline on the required competency level for all personnel and how it could be achieved.
Hosting more engagement sessions closer to first oil between the operations team and project team.
This paper shares: The challenges faced by the project. Details on building a competent team to successfully startup and operate ESP wells. Early results and performance of the operations team. Lessons learnt and next steps.
The challenges faced by the project.
Details on building a competent team to successfully startup and operate ESP wells.
Early results and performance of the operations team.
Lessons learnt and next steps.
Geissler, Brett (Nalco Champion, an Ecolab Company) | Jones, Alicia (Nalco Champion, an Ecolab Company) | Setinc, Marty (Nalco Champion, an Ecolab Company) | Koerner, Alex (Nalco Champion, an Ecolab Company) | Binek, Damon (Nalco Champion, an Ecolab Company)
Due to its contribution to microbiologically influenced corrosion and potential HS&E consequences, hydrogen sulfide (H2S) presents many challenges to oil and gas production operations. Microbiologically generated H2S is often more difficult to address, because it is not present at the onset of production, but becomes a problem over the course of the lifetime of a well/asset. Many different types of microbes are responsible for H2S production and reservoir souring. These microbes are capable of reducing, not only sulfate, but most available sulfur compounds that are present in the reservoir. A new class of compounds was recently identified and characterized in the lab as effective inhibitors or microbial sulfidogenesis. In this work, we present results from a field trial conducted using one of these chemistries. The trial showed that this novel inhibitor retained activity under downhole conditions and resulted in significant reductions in the H2S produced within the reservoir as well as the levels found at the central gathering facility. These findings further support the potential of these compounds as solutions to reservoir souring and highlight the need for additional field applications.
Microbiological reduction of sulfur compounds to hydrogen sulfide (H2S) within oil and gas production systems can have detrimental impacts on production, asset integrity, as well as lead to HS&E concerns. More specifically, H2S generation within hydrocarbon reservoirs by sulfate reducing prokaryotes (SRP) leads to souring of produced fluids and gases which plays a major role in microbiologically influenced corrosion and devalues these products.1,2
Current Reservoir Souring Treatments
To date, very few chemistries or treatment strategies have been identified that are effective at preventing and/or mitigating reservoir souring. Application of conventional biocides (THPS, glutaraldehyde, quaternary ammonium compounds, etc.) often prove unsuccessful because they are not able to reach the responsible microbes downhole. Alternatively, compounds intended to alter microbial populations through metabolic selection require high dosages and consistent application in order to be fully effective.1,2 Therefore, novel molecules that show promise in inhibiting biotic sulfidogenesis within the reservoir at low dosages are highly desirable to prevent disruptions to operations and lower production costs.
Temizel, Cenk (Aera Energy) | Canbaz, Celal Hakan (Ege University) | Palabiyik, Yildiray (Istanbul Technical University) | Putra, Dike (Rafflesia Energy) | Asena, Ahmet (Turkish Petroleum Corp.) | Ranjith, Rahul (Far Technologies) | Jongkittinarukorn, Kittiphong (Chulalongkorn University)
Smart field technologies offer outstanding capabilities that increase the efficiency of the oil and gas fields by means of saving time and energy as far as the technologies employed and workforce concerned given that the technology applied is economic for the field of concern. Despite significant acceptance of smart field concept in the industry, there is still ambiguity not only on the incremental benefits but also the criteria and conditions of applicability technical and economic-wise. This study outlines the past, present and the dynamics of the smart oilfield concept, the techniques and methods it bears and employs, technical challenges in the application while addressing the concerns of the oil and gas industry professionals on the use of such technologies in a comprehensive way.
History of smart/intelligent oilfield development, types of technologies used currently in it and those imbibed from other industries are comprehensively reviewed in this paper. In addition, this review takes into account the robustness, applicability and incremental benefits these technologie bring to different types of oilfields under current economic conditions. Real field applications are illustrated with applications in different parts of the world with challenges, advantages and drawbacks discussed and summarized that lead to conclusions on the criteria of application of smart field technologies in an individual field.
Intelligent or Smart field concept has proven itself as a promising area and found vast amount of application in oil and gas fields throughout the world. The key in smart oilfield applications is the suitability of an individual case for such technology in terms of technical and economic aspects. This study outlines the key criteria in the success of smart oilfield applications in a given field that will serve for the future decisions as a comprehensive and collective review of all the aspects of the employed techniques and their usability in specific cases.
Even though there are publications on certain examples of smart oilfield technologies, a comprehensive review that not only outlines all the key elements in one study but also deducts lessons from the real field applications that will shed light on the utilization of the methods in the future applications has been missing, this study will fill this gap.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.