|Tuesday, September 12|
|Evening||Cocktail Reception - Pavilion Royal|
|Wednesday, September 13|
|Morning||Opening and Plenary Program|
|Executive IT Program|
|Evening||Gala Dinner - Palais Garnier Opera|
|Thursday, September 14|
|Executive Exploration Program (Invite Only)|
|Executive Drilling Program (Invite Only)|
|Evening||Informal Dinner - Bateaux Parisiens|
|Friday, September 15|
|Afternoon||Lunch and Closing Ceremony|
|Data & Analytics|
Scroll down to read a selection of the abstracts that will be presented at the SIS Global Forum
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Cepsa Corporate PDMS: From Data Capture to Production Optimization
Cepsa is an integrated oil company with headquarters in Madrid, Spain. The E&P operated activities are in Colombia, Peru, Algeria, Thailand, and Malaysia. The existing production management and allocation system was implemented in 2004, and a new, modern system was required. Furthermore, new business units had been acquired over the years, which had their own production management and allocation systems. Consequently, a key consideration was to acquire and implement one system across all business units.
With Cepsa E&P´s history and ambitions in mind, the system had to allow easy inclusion of new fields and business units. The Cepsa business units are small, and to mobilize the critical mass of the company-wide production technology teams, the system had to enable collaboration between the local assets and the corporate production technology team. On this basis, a vision was created for the foundation of the digital oilfield in Cepsa-operated ventures.
Cepsa deployed the Avocet production operations software platform for all their assets, thus implementing a solution based on a production data management system (PDMS) to meet the imminent needs of replacing outdated technology and to provide the starting point for the future requirements and vision. The solution covers Cepsa-operated and nonoperated assets; it is deployed centrally in Madrid and accessible from the assets through the Cepsa IT network.
The project delivers a production operations management and decision support system integrating
- Data management: Data capture, QA/QC, centralized and accessible data storage allowing integration with other disciplines and applications
- Visualization: Production monitoring, reporting trends, analysis and KPIs, and subsurface and facilities surveillance
- Production system optimization: Permanent well performance monitoring using direct linked models to assess efficiencies for artificial lift systems, facilities capacities, identification of losses, among others.
- Reservoir and asset optimization: Field planning and forecasting
Deterministic Simultaneous Inversion for Reservoir Delineation and Fluid/Lithology Characterization using the Petrel Quantitative Interpretation Tools
The value of the Petrel Quantitative Interpretation tools for reservoir delineation and fluid/lithology in a Triassic gas field was assessed.
The three-step assessment workflow comprised
- An initial, log-based, inversion feasibility analysis
- Deterministic simultaneous seismic inversion including low-frequency model building and inversion parameterization
- Quality checking and interpretation of inversion products
For each step in the workflow, highlights, pitfalls, and limitations of the current Petrel Quantitative Interpretation toolbox implementation were determined.
In the test study, an initial feasibility analysis was performed to test the suitability of the seismic data quality and local rock properties for lithology and fluid discrimination via inversion. Crossplot analysis showed that a fluid-sensitive modulus attribute can be used effectively to discriminate between brine- and gas-bearing sands, with gas sands showing the lowest attribute values. Fluid substitution in synthetic image-gather modeling shows a clear increase in amplitude when brine is substituted with gas. Additionally, comparison of the partial angle stacks at the gas discovery well location shows a clear increase in amplitude with angle.
The seismic inversion phase consisted of (1) trace alignment (seismic trace alignment module); (2) well tie (seismic well tie module); (3) deterministic, angle-dependent wavelet estimation (wavelet extraction module); (4) low-frequency modeling (inversion property builder); (5) inversion (simultaneous inversion module); and (6) QC of the results. Deterministic simultaneous inversion was conducted integrating the four partial angle stacks, the angle-dependent wavelets, and the low-frequency models using the Petrel inversion algorithm for P-impedance, Vp/Vs, and density. The results were then quality-checked in the data space by inspection of the residuals between the inverted synthetic and input reflectivity data and the relative misfit and in the model space by plotting the measured logs versus the inversion results extracted at the well location. Finally, a fluid/lithology-sensitive volume was computed from the inverted volumes, and a strong correlation was achieved between the derived fluid attribute results and the gas-bearing sands.
The final phase of visualization and interpretation of the results consisted of attribute extraction, stratal slicing, and geobody extractions. These techniques were all effectively used to discriminate between sands and shales and delineate the gas-bearing sands with the lowest fluid attribute values. Although most of the Petrel Quantitative Interpretation tools were successfully implemented in this reservoir characterization study, some opportunities for improvement were identified, including simplifying inversion parameter testing, inversion results QC, and stratal slicing.
Developing the Full Field Simulation Model of a Fractured Basement Reservoir, West of Shetland, using INTERSECT
Fractured basement is productive around the world, and yet, despite offering significant resource potential, this reservoir has been underexplored and overlooked as a play within the UKCS. Hurricane is a forerunner within the industry in exploring this play and has successfully made two sizeable discoveries (Lancaster and Whirlwind, each ~200 million BOE 2C recoverable resource) since 2009 in the UK West of Shetland province.
As a type 1 naturally fractured reservoir (NFR), fractured basement has no effective matrix porosity or permeability; consequently, production efficiency relies entirely on a hydrodynamically connected natural fracture network. This results in a specific set of challenges that must be accommodated as part of the workflow when building static and dynamic models of basement reservoirs. Hurricane has been using the Schlumberger INTERSECT high-resolution reservoir simulator to enable high-resolution, geological-scale simulation of the Lancaster discovery to history-match Hurricane’s successful 2014 horizontal appraisal well test and investigate uncertainties, leading toward full-field development.
Hurricane presented at the SIS Global Forum 2014 in Barcelona on the work that had been performed utilizing Schlumberger tools and software to develop a robust static model. Although the dynamic modeling was at an early stage, the benefits of using the INTERSECT simulator were clearly demonstrated. This study continues from that early work, to encompass the development of the full-field pseudo-single porosity model that was used to achieve a good match to the well test data of horizontal well 205/21a-6, work that was performed in close collaboration with Schlumberger.
This first phase was considered a pseudo-single porosity model because the well test analysis of 205/21a-6 revealed (as Hurricane had suspected) that the Lancaster fractured basement reservoir exhibited dual porosity behavior. This dual porosity is caused by the interaction of different scales of fractures within the hydrodynamic fracture network—it remains a type 1 NFR with no effective matrix porosity or permeability. For initial modelling, a simplified approach was desired. However, to honor the data and achieve a robust history match, Hurricane ensured the initial model utilized the dual porosity interpretation in calculating the average parameters to be used in the geocellular grid. Ongoing work has focused on incorporating a realistic discrete fracture network (DFN) into the model and performing a full-field simulation on an exceptionally large dual porosity model using the INTERSECT simulator.
Establishing a suitable dynamic modelling workflow for Lancaster has beneficial implications not just for Hurricane’s remaining basement assets, but also for unlocking the basement play within the UKCS.
ETAP's Database Management Enhanced through Migration to ProSource
ETAP, the Tunisian National Oil Company, supervises exploration activities and directly participates in all hydrocarbon-related operations in Tunisia. As per the E&P rules, every operator in Tunisia should provide ETAP with different types of petrotechnical data.
In this respect, ETAP is responsible for safeguarding Tunisia’s E&P heritage and is responsible for acquiring, securing, storing, and managing all the data. A relational database was deployed in early 2000 based on Schlumberger technology of the time: AssetDB, LogDB, and SeisDB software for managing information assets, log data, and seismic data, respectively, and the Finder data management system. As the solution has developed, it has become difficult to manage due to the existence of many separate databases, some inconsistencies of stored data, and lack of defined workflows and collaboration between teams. The difficulty in managing ETAP’s databases was the compelling reason for migrating the existing systems to an up-to-date technology and to set up real data management policies. This migration will help the database fulfill its objectives of efficient management of data and providing easy and fast access to these stored data.
ETAP is currently initiating a pilot project that aims to create a national data repository that would enhance the overall return on investment of the database and establish better data management practices.
By offering an end-to-end solution that ensures the connectivity of all the data stores under the advanced Seabed* data model and enabling management of data on different administration levels, the Schlumberger ProSource* E&P data management and delivery system helped in solving most of the ETAP database issues.
The delivery of this database project started with a series of assessments of the existing data stored in the different databases as well as interviews done with all key users. Based on the assessment reports and findings, both ETAP and Schlumberger agreed on a project methodology to follow for the upgrade and migration to the ProSource system. The project was successfully delivered in 6 months. ETAP’s database staff benefited from the ProSource training sessions and took advantage of the time spent with the SIS team of consultants to conduct key enlightening discussions.
After data were successfully migrated to the ProSource system, the database staff began developing well-defined and domain-specific workflows, designing their learning and development programs, and establishing and applying standardization procedures. Based on this work, teams were restructured, and an intensive data loading, quality checking, and validation activity started in a collaborative working environment.
The adherence to higher levels of data management policies throughout the scalable ProSource system has so far helped increase trust in the quality of stored data, which, in turn, will remedy the lack of collaboration among the company departments.
Integrated Formation Evaluation using the Techlog Platform in a Complex Clastic Reservoir, Cheleken Block
This study was conducted in offshore field, located 20 km west of the Cheleken Peninsula, Turkmenistan. The studied stratigraphic sequence within the field consists of early to middle Pliocene sandstone reservoirs.
The reservoir development department of Dragon Oil planned to acquire a massive formation evaluation suite to better understand the geology and structure of the unexplored part of the Zhdanov field. The LWD BHA included a triple-combo log suite with the EcoScope LWD multifunction service in the 8.5-in. section to provide comprehensive data in real time. The wireline logging included the quad combo (the Platform Express integrated tool and the Sonic Scanner platform), NMR, MDT sampling-fluid identification, and sidewall coring. A total of 14 sidewall cores were acquired. Detailed core analysis will be performed.
The main objectives of the openhole logging were the following:
- Perform real-time formation evaluation of reservoir with LWD and wireline logging tools
- Identify the fluid type and calculate porosity and permeability by NMR fluid mapping
- Correlate wells in reservoir areas, which are highly compartmentalized by faults
- Interpret images where applicable
Density image interpretation was done by Schlumberger PTS. The image interpretation supported the seismic fault interpretation, thus confirming the structural interpretation of the field. A reverse fault was confirmed in one of the wells, which was supported by openhole logs, image interpretation, and MDT pressures.
The integrated formation evaluation interpretation of every well was performed in the Techlog platform. It included petrophysical interpretation, borehole image interpretation, and fault analysis integrated with seismic interpretation. Two different pressure regimes were identified with the help of sonic/resistivity logs and were confirmed by MDT pressure data.
Successful Production Monitoring of Large Brown Heavy Oil Field with Several Thousand Wells
The Karazhanbas field (KBM) is a large, shallow, heavy oil field in western Kazakhstan, less than 500 m deep. It is the only heavy oil field in the country producing with steamflooding. Discovered in 1974, KBM has more than 3740 wells, producing two millions tons of oil; the steamflood region contributes almost half of the oil produced. To help manage the field, the Avocet production operations software platform provides the production data management (PDMS) and the OFM well and reservoir analysis software was implemented for reservoir monitoring and management of the field’s complex enhanced oil recovery (EOR) operations.
Over the last decade, KBM deployed and has rigorously maintained a robust PDMS, monitoring, and surveillance process, enabled by SIS production software technologies and services. This has enabled KBM to have continuous access to a holistic visualization of the performance of its large field operation, which has enabled timely response to detected problems and critical decision-making.
The deployed solution provides the required production data quality control, data storage, visualization, and allocation process, reporting essential day-to-day production and injection strategic information. It delivers a reliable, easy-to-maintain data architecture to connect, store, manage, validate, and report information—enabling KBM to have a comprehensive picture of its field for the entire set of wells and equipment, along the EOR-implemented cycles.
To analyze in-depth production and injection field performance, the OFM application has been configured and linked to the Avocet platform, where dedicated templates such as plots, reports, and maps have been created to address the specific requirements of KBM reservoir monitoring.
The OFM master project is always current with the most recent QC operational data gathered from the field, and thus constitutes a single trusted source of information that is shared amongst personnel from field site engineers to office reservoir and production engineers, including third-party institutions performing and monitoring the KBM field development plan.
The Role of Mobile Shale in Forming Fold Belt Anticlines and Hydrocarbon Accumulations in Sabah Basin, Malaysia
The Sabah basin located in offshore Sabah is a well-known oil and gas production area of Malaysia. The thickness of sediments in the Sabah basin is up to 12 km in its deepest depocenter. Many of the oil and gas fields are associated with toe-thrust anticlinal structures. Up to 80% of all the drilled structures, prospects, and leads may be related to shale diapirs. It is often difficult to distinguish overpressured shale from the effects of gas on seismic sections in these deepwater structures because the acoustic velocity of overpressured shale is comparable to that of gas-saturated formations (as low as 1500 to 1700 m/s). This necessitates careful analysis of mobile shale analogs in the vicinity. In general, shale ridges have smooth surfaces, whereas intrusions exhibit pipe-like morphology. The intrusion of mobile overpressured shale typically causes deformation and fracturing of the surrounding sediments, which may affect the underlying source rock interval, thus facilitating hydrocarbon migration. In this study, we modeled the movement of shale bodies by assuming a constant shale area during structural deformation and by applying the algorithms for intrusion and fracturing in PetroMod 2DTM software. Two “shale facies”—stable shale and mobile shale—were established for mobility modeling with different physical parameters such as density, viscosity, frictional angle, and cohesion. During pore pressure evolution, it is noted that when pore fluid pressures reach up to 80% of lithostatic stress, hydraulic fracturing will occur and fluids are expelled from stable shale. On the other hand, the light, highly viscous shale with a lower frictional angle will start to mobilize. In the latter model, the effects of forces due to Pliocene tectonic inversion were also modeled by adjusting the boundary conditions, including pressure, displacement, and shearing. The modeling results show that the shale mobilization can contribute locally to high pore pressure gradient up to the fracture gradient and can result in fractures and higher permeability near the mobile shale. The resulting fractures will facilitate fluid flows, including hydrocarbon migration both vertically and laterally.