The Daisy Chain subsea termination of umbilical breaks out the services housed through it, distributing them to the onward equipment (X-Trees, Manifolds, SDUs) by means of infield flying leads.
An innovative subsea umbilical termination design has been developed by GE Oil&Gas in order to meet the ultra-deep-water field requirements in a competitive market scenario, where the oil price downturn requires to be focused on the cost reduction. The innovative subsea umbilical termination is to be installed with the conventional umbilical installation steps , while housing the functionality required by a daisy chain field architecture which does not provide the usage of additional distribution blocks. The new family of subsea umbilical termination is suitably designed for water depths up to 3000 m, for umbilical transition spools  up to Class 300 – 20 inches Nominal Pipe Size as per ANSI B16.5 –, for connecting together up to six off infield flying leads allowing chemical/hydraulic power distribution and twelve off flying lead allowing the electrical/optical power distribution.
From a structural point of view, the new family of subsea umbilical termination includes a main frame made up of tubular beams and a secondary frame of plates welded / bolted to the main frame itself. Fully designed to meet the requirements of the DNV-2.7-3 , it guarantees a Payload up to 80000 Kg. The Installation methodology can vary according to the Customer requests: horizontal tensioner and over boarding system, horizontal tensioner with vertical over boarding system, closed vertical lay system and open vertical laying system  can be adopted. The first UTA of this new family has been successfully installed at the beginning of 2016 in the Indonesian seas and it is currently working: this means that the new design philosophy has got a technology readiness level of six, in accordance with the API 17N . A further subsea field will be provided within the middle of 2017: a fully daisy chain architecture with the “new” GE subsea umbilical termination as key element. Future is changing: GE is adapting its technology to drive this change providing to our Customer the way to win.
De Filippis, P. (Università La Sapienza) | Napoli, F. (Università La Sapienza) | Giorgio, B. (Università La Sapienza) | Grechi, M. (Università La Sapienza) | Nolè, C. (Università La Sapienza) | Quattrocchi, F. (INGV) | Santoleri, R. (COESUM)
The full paper was not available when this collection was edited.
The public acceptance of any industrial activity from local populations cannot disregard from sharing the knowledge of production cycle.
From this point of view in the 2014/15 we started a new research project with the main objective to develop a 3D interactive model of a hydrocarbon reservoir to assist in the transfer of technical information regarding E&P operations.
The specific end user targeted for this project were those stakeholders naturally, who are not necessarily professionals in this technical area.
The first 3D pilot prototype with 0.60*0.30*0.01 m and a scaling rate of 1:25.000 was obtained by correlating for a real ON-SHORE reservoir with equal size to 14,000 * 7,000 * 200 m (L*W*H only of reservoir andf wells).
Thanks to the good results achieved with this first attempt, we created a new complete 3D prototype of an OFF-SHORE reservoir with more details, as wells+faults+saline aquifers+seabed+rocks stratigraphy, and with a less scale rate of 1:15,000 (3D prototype size 0.8*0.30*0.5 m) was created by correlating for a real reservoir with equal size to 12,000 * 5,000 * 5,000 m. (L*W*H for the entire volume considered).
The project turned out as a vision for what happens in 2016 when the poor knowledge of non-expert people about the technology used in the O&G industry led in Italy to a referendum on exploration and offshore licences development.
In this regard it is worth noting that only in the Basilicata Region, where is located the largest onshore reservoir of Europe, voters to the referendum exceeded 50% to confirm the opposition of new ‘DRILLS’. (cfr. NOTRIV)
So, before, during and after the mentioned referendum, this last 3D prototype was shown to university students, people with different age, diverse cultural background: the result was that people increase their level of awareness on oil field, the extension of the reservoir and what mean a E&P project and the exploitation of subsoil under their land.
3D-RES project vision, that appeared futuristic some years ago, actually finds its perfect mission on the implementing of UE Regulation “TEN-E” on Public Debate and the resulting Decree of Italian Ministry of Economic Development (29th Jul 2016).
Aim of this work is to present the evolution of the 3D real reservoir project, focused on a more realistic representation of field, believing that it may represent a powerful clear and intuitive tool for sharing the scientific knowledge in O&G operations: we are ready to show a new 3D reservoir prototype with a scale rate 1: 5,000 that means a size 2 * 2 * 1.5 m. (L*W*H).
The dynamic characterization and the description of fluid flow behavior at well location are critical steps for production optimization and reservoir modeling purposes. The conventional approach makes use of well test data interpreted by adopting appropriate analytical models aimed, in particular, at permeability evaluation and flow regime identification. In complex reservoir scenarios, the standard well test interpretation lacks a direct link with the actual flowing thickness of the reservoir rock and this represents the major cause of inaccurate permeability estimations. Moreover, an a-priori knowledge of fluid flow path through the porous medium and around the wellbore is one of the most desired targets but, at the same time, one of the most challenging issues to be addressed.
This paper deals with a novel dynamic characterization approach that mainly integrates well test data and spectral noise logging. The latter, with its high-resolution noise pattern recognition in a wide frequency range, can provide valuable information of the fluid flow behavior in the near wellbore region in order to locate the active units and to describe the origin and the character of the flow (through mesopores, macropores, fractures, behind-casing channels and completion elements).
The added value of the methodology is demonstrated by means of a study performed on three wells drilled in a Cretaceous carbonate reservoir. The accurate estimation of the net-pay flowing thickness, after a fit-for-purpose modeling of noise data, revealed the subsequent robust estimation of effective permeability and different scenarios with respect to those based on standard approaches. Then, the integration of quantitative spectral noise analysis, pressure transient tests, production logging data, and advanced nuclear magnetic resonance log interpretation completed the picture of the flow regime through the pore-space. In turn, the results represent a critical input for the dynamic reservoir model, and a fruitful driver to optimize commingled completions or required workovers.
The deep understanding of fluid movement from sandface to surface is a critical aspect in production optimization and reservoir modeling studies. According to conventional approaches, the actual dynamic characterization of a well usually comes after production logging tool (PLT) data interpretations and/or well test (WT) analyses.
The current oil price scenario is strengthening the industry’s attention towards a more efficient energy usage. This paper shows the energy saving results obtained from field application of an innovative tool for the integrated production optimization of surface facilities based on a genetic algorithm. The objective function of the tool is tailored for each of the described case studies in order to increase field production and reduce energy consumption. The presented tool integrates well performances, gathering system calculation, and process plant simulation in order to optimize the field configuration with a global perspective. Conflicts and interactions between variables, constraints, and operational limitations are balanced and solved holistically by the optimization tool. For each of the field application case studies presented a tailored energy efficiency objective function is defined to optimize production and energy consumption. A powerful evolutionary algorithm searches for the optimum field configuration that represents the best trade-off between efficient usage of energy resources and production maximization. The integrated production optimization tool has been applied on different fields with the aim of simultaneously increasing the energy efficiency of the assets and optimizing production. The benefits of the integrated optimization tool to boost energy efficiency have been proved on an offshore field application. The action suggested from the optimization tool permitted production increase, reducing the global energy losses of the system. A second application is presented, where a significant energy saving has been achieved by the optimized configuration suggested from the tool to recover production after a process upset. All the described applications show a relevant energy saving in terms of primary energy consumption, associated with the increase of field production. This paper describes an innovative approach to increased energy efficiency in oil and gas industry operations. The application of the integrated production optimization tool showed its benefits by improving process and equipment operations and reducing associated operating costs without capital expenditures on energy efficiency.
The extension of production life for brown field is a key element for the asset sustainability, especially in this low prices scenario environment, considering also that the amount of investments and their return is an essential driver during all the decision making process.
For that reason EOR techniques are good opportunities to be exploited since the production facilities are already developed and the investment level is highly below the green field requirements.
The EOR implementation requires the introduction of new technologies and an unorthodox thinking approach is mandatory to face new cost and technological challenges.
This work describe the rejuvenation program implemented for Belaym Land Oil Field, an onshore giant mature asset in production since 1952, currently developed by means of peripheral seawater injection.
Since 2014 an intensive plan of R&D EOR pilots have been screened and 3 techniques have been selected and are under test now: Polymer Flooding, Low Salinity and Bright Water Injection.
The overall program is the integration of different disciplines: reservoir, flow assurance, production, maintenance, project and IT in order to better integrate the selected EOR techniques surface facilities with the existing plant, in term of equipment rejuvenation, process interaction, future power demand & flow assurance.
In order to provide an effective and reliable support to the program a new management system based on real time data integration is under development and it will be fully embedded.
The well & plant field data captured live through customized developed smart devices (Space box) will feed live the reporting & monitoring system and support the multidisciplinary engineering team in the models analysis (ESP, Process, Reservoir etc.) and in the decision making process.
Program final targets will be not only the full field implementation of the best EOR combination techniques for Recovery Factor increase, but also the maximization of the full asset operations efficiency (i.e. cost optimization, downtime reduction).
In order to solve sand shale sequences tie mystery, four sequences were proposed for Late Messinian, Abu Madi Formation, which is a multi story fluvial channel system recorded and represented completely in the off shore area with maximum thickness about 320 m. Relative energy, accommodation space, sediment supply, reservoir quality and thickness are decreasing with time starting from sequence one to four, from bottom to top respectively. Each sequence containing three system tracks with a definite sand distribution trend, and subdivided into 13 layers with 10 zones and 9 tested reservoirs.
Early Messenian, Qawasim Formation complex channel system composed of two sequences underlying Abu Madi channel with 500 m average thickness. Upper sequence (sequence two) is occasionally eroded, it can be subdivided into 6 layers with 5 zones and 4 tested reservoirs. Lower sequence (sequence one) which is preserved but not completely penetrated in all studied wells is characterized by an average thickness about 240m and divided into 5 tested reservoirs in the relatively high structure block in onshore area.
Sequences Three and Four in Abu Madi Formation and sequences One and Two in Qawasim Formation can be easily discriminated by the different tools and became the main goal in the exploration strategy in the area. Accordingly, three successive exploratories and six development wells were drilled to explore and exploit these sequences and resulted in high daily production rate about 70 Mscft per well achieved.
The exploration activity in the study area about 4550 Km2 focused on onshore Messinian incised valleys as exploratory successful play after the great Abu Madi field (1976). The offshore discoveries, (Baltim East and Baltim North, 1970s and 1980s) were discovered on the extension of this play with a lot of uncertainties about where exactly is the play borders start and end. NW direction is the main orientation trend for reservoir but who go deeper in detail facing with question not easy to solve especially when leakage of data can judge clearly. Some fields as Abu Madi, Baltim East and Baltim North have original gas/water contact for each zone while El-qaraa field show partial sealing and degree of fault transmissibility with production. On other hand, Nidoco field shows multi gas/water contact, production index and cumulative production show a lot of variance comparing with surrounding fields.
The Nile Delta province covers one of the world’s great Tertiary deltas. The province encompasses approximately 250.000 km2 of the Eastern Mediterranean area.
The Mesozoic-Cenozoic composite petroleum system for Nile Delta basin was defined to include the source rocks of Jurassic, Cretaceous, Oligocene, Miocene, Pliocene and Pleistocene ages.
Many fields have been proved by PVT samples and production data, the presence of thermogenic gas and condensates in the Pre-Messinian reservoirs (Wakar, Sidi Salem, Qantara and Tinah Fms), while the Plio-Pleistocene section has been proved mainly as a biogenic gas potential. Thermogenic gases have been recorded also in some cases in the Plio-Pleistocene section; these gases being generated from the pre-salt section and migrated along faults and /or gas chimneys.
Oil has been discovered in the eastern side of the Nile Delta basin in both onshore (Qantara oil discovery) and offshore (Tineh & Mango oil discoveries).
Recently, oil has been discovered in the Pliocene reservoirs in the eastern offshore of the Nile Delta Basin. Bore hole samples indicate an oil gravity of 42 API degree with an gas oil ratio of 708.54 Scf/stb.
This oil is likely to be originated from a deep source rocks and migrated along a fault planes which acts as a good conduit for hydrocarbon migration.
According to geochemical analysis the Pliocene oil would appear to be evaporated oil, which opens the gate for oil exploration in the deeper intervals.
Over the past 35 years more than 4.0 BBOE have been discovered in the Nile Delta, primarily as gas and condensate. Figure 1shows a location map of the area presented in this talk. With the discovery of Pliocene oil in the Eastern Nile Delta, given that such considerable amounts of oil are known, it is logical to ask “Where has it come from and when was it forms?” the answer may provide clues to discovering yet more oil in less obvious places.
Young unconsolidated terrigenous sediments represent the general geological context where the main offshore Adriatic fields are located. In such geological environment, sea floor subsidence, caused by hydrocarbon extraction, could eventually occur. In Italy in order to prevent any possible impact of the hydrocarbon production activities on coastal areas environments and infrastructures, before starting-up a new hydrocarbon off-shore development project, a monitoring plan to measure and analyse total subsidence evolution has to be submitted to the Italian Authorities. Though many tools are available for subsidence monitoring onshore, few are available for offshore monitoring. ENI, in order to fill the gap, conducted a research program, with different suppliers, to generate a monitoring system tool to measure seafloor subsidence. Advanced feasibility studies have been carried out with three different companies: Company 1; Company 2 and an Italian company, AGISCO, operating in the field of geotechnical instrumentation and consulting. Company 1 and Company 2 proposed the use of interesting technologies (respectively based on fiber optics and electrical tiltmeters), but with a technology readiness level lower than AGISCO’s one, that proposed an advanced solution based on already available industrial components and easily implemented up to desired size. The AGISCO proposed tool was based on the internal cable altitude-dependent pressure changes, measured using pressure transducers. The AGISCO tool had already several applications on shore in dry/semi-dry places, but has never been applied to offshore subsidence monitoring for oil and gas industry. The company, in 2015, built for ENI the first prototype of the tool. The tool, according to ENI technical specifications resulted as a robust cable, with variable outside diameter (from 40 to 140 mm) and 100m interval spaced measuring points. The paper, through the design of instruments from the three companies, describes the process that has led to the choice of Agisco tool and outlines the future steps that will have to be taken towards the installation of the tool.
ENI Upstream & Technical Services, as any others Oil Company involved in hydrocarbon exploration and production projects in Italy, particularly for the offshore fields located in the central-northern Adriatic sea, is obliged, by authorities to define a monitoring plan able to foresee, measure and analyse in semi-real time probable subsidence evolution before any gas production. The plan must manage any possible impact, direct or indirect, of the production project on the coastal areas and on the adjacent inland.
Leadership in Health & Safety – Driving Cultural Change in an Offshore Fleet
Maintaining a strong culture of safety presents numerous challenges to the leaders that operate within our organization.
This paper will demonstrate the methodology that is employed in the assessment, planning and execution of our Leadership in Health and Safety program within our offshore business unit in order to maximize the positive effects of cultural change.
Since its launch in 2007 Saipem’s Leadership in Health & Safety program became truly embedded in the organisations DNA, within daily actions and decisions, and the unseen mind-set triggering this. We have achieved a unified vision of a single safety culture through continuous engagement with our offshore vessel management teams & supervisory personnel. We have developed these key roles to be true safety leaders and to further disseminate our safety culture to the people within their sphere of influence.
Our cultural safety training programme is tailored to accurately meet the demanding needs of the population and collaborative training events are undertaken in order to cross pollinate concepts and ideas and the release of multiple ‘phases’ ensures the change process is nurtured and remains omnipresent.
Staggering improvements are evident in terms of organisational safety performance, a very definite year-on-year accident frequency reduction totalling over 50% since the LiHS process was launched, whilst proactive safety observations increased by 70%. Organisational locations where the program implementation was poorly communicated (mainly due to local commitment), sees these positive results lagging. A strong correlation exists between sharp increases in proactive safety observation, with launching of new phases. Reporting gradually decreases over several months, and again spikes with in line with new phase releases. The change process is still ongoing, and constant feeding is critical to ensure high levels of visibility is maintained.
Gouda, G. (Eni Egypt) | Kaja, M. (Eni Egypt) | Abdel Fattah, S. (Petrobel) | Shaker, E. (Petrobel) | Abd ElHakim, W. (Petrobel) | Korany, M. (Petrobel) | Samir, E. (Schlumberger) | Metwally, A. (Schlumberger)
Abu Rudeis Field is considered one of the oldest oil fields in the Gulf of Suez, Egypt, producing since 1957. Most of the oil production comes from the Nukhul sand, which resulted in the depletion of this zone. The depletion of the Nukhul sand creates a challenge for the drilling engineering in terms of the optimum well design and the drilling methodology to implement, which would help reduce the drilling costs and ensures smooth drilling operation for early production. The focus of this paper will be on the ARM block in the Abu Rudeis Field where recent field studies has shown that better production rates can be achieved from drilling horizontal wells as compared to drilling deviated wells. Four horizontal wells were drilled in the ARM block and for all four wells; a pilot hole was drilled in order to determine the unconformable top of Nukhul Sand Formation. The pilot holes that were used to determine the sand top was then plugged and abandoned and side-tracks were drilled for a build-up section whose casing point selection was made based on the pilot hole data. Failure to set casing at the top of the reservoir sand would result in complete mud circulation losses due to the difference in pore pressure between the depleted sand and the pressurized shale above it. The analysis of the nonproductive time including the pilot hole cost, the sticking pipe risk and the possible oil based mud losses ranged +/- 1.8 M$.
This paper highlights the engineering solution and the technology usage of the first reservoir mapping while drilling service in Egypt to land a horizontal well with proactive detection of the casing point in order to eliminate the nonproductive time associated with drilling pilot holes. The main objective is to continue drilling more horizontal wells in order to increase the oil production from the field.