While distributed temperature sensing (DTS) has become a commonly used tool in reservoir studies, the technology has not seen widespread use in SCAL projects. Most core-scale experiments attempt to control temperature at a constant value rather than monitor temperature changes within a sample during a test. High-resolution temperature arrays are available that measure changes in temperature of 0.1°C at 1-mm resolution. The optical backscatter reflectance (OBR) fiber senses both temperature and strain that can be separated through experiment design and signal processing. These OBR fibers are sensitive enough to monitor temperature changes associated with endo- and exothermic chemical reactions associated with mineral dissolution/precipitation, or fluid-front movements in steam-assisted gravity drainage of heavy-oil tests. An example of the use of a distributed temperature array is in the monitoring of natural-gas-hydrate formation and dissociation in a sandpack as CO2 is exchanged with the naturally occurring CH4 in the hydrate structure. A fiberoptic array was placed within a narrow-diameter PEEK tube as the sandpack was constructed. The PEEK tube held the fiber optic in place so that the sensed signal was temperature only and did not include any strain effects. The OBR was set up to acquire a temperature array every 30 seconds during the test at 5-mm spacings. The core holder was placed in a MRI instrument that provided additional spatial information on hydrate formation during the test that was compared with the OBR results. Initial hydrate formation resulted in a several degrees increase in temperature at the inlet end of the cell that with time, progressed down the length of the cell. The temperature array and MRI images both showed the nonuniform nature of hydrate formation and subsequent dissociation of the hydrate when N2 was injected into the cell as a permeability enhancement step. The faster response of the OBR array compared to the time required to acquire MRI images provided additional detail in the sequence of hydrate formation and dissociation during CH4-CO2 exchange. The limitation to the OBR array was that it only sensed temperature fluctuations proximal to the fiber as a function of the hydrate system’s thermal conductivity.
Pipeline inline inspection requires a proper cleaning of the pipeline inner walls. In the case hereby described of a 30km 12" offshore line, a significant amount of wax deposits was expected and a series hydromechanical cleaning tools were deployed, after a preliminary series of less aggressive pigs. Normally, the progress of the cleaning process is monitored only by the arrival conditions of the cleaning tools and of the receiving trap. To improve the process, miniaturized pressure, temperature and acceleration sensors were added to the cleaning tools, directly in the field, without any modifications to the cleaning devices and without introducing any additional risks or operating impact. After each instrumented cleaning tool, the sensor data were quickly analyzed and led to the selection of most suitable subsequent tool. In this way, it was observed that the pig conditions and the amount of material collected in the receiving trap did not fully indicate the true cleaning status of the pipeline, while the sensors provided a clearer picture. The pig sequence was thus optimized in number and type of pigs and the intelligent pig run was preformed successfully with no issues or data loss. The advantage of these tiny sensors, not foreseen in the hydro-mechanical pig design, is that they can be applied to almost any pig with minimal-to-no modifications. This information can be used in a number of ways, including detection of flow restrictions (dents, deposits), and can also be used to recreate the line elevation, profile with limited a priori information.
The paper describes the complete workflow applied for the future development of the Oglan Field in the Ecuadorian Oriente Basin in a sanding potential scenario. First, a sand prediction study evaluates a potential risk of sand production in a certain range of drawdown, identifying 1000 Psi as the critical one. Then, the conceptual evaluation of sand production mechanism is presented and discussed, in order to define the most suitable completion method for the production section.
The methodology is based on a Geomechanical characterization done over the Oglan 2Dir cores, which includes stress evaluation, and the definition of the geomechanical properties needed for the sand prediction model. The procedure integrates results from Scratch tests, Triaxial, Ultrasonic Tests, Geo-pressures and Log processing. Once the sand production potential was identified the evaluation of a suitable downhole sand control method becomes necessary; grain size analysis, sand sorting ratios, reliability, productivity are evaluated to identify the optimal sand control technique. Finally, a sand production comparison for Hollin Formation in Ecuador is performed.
The initial section of the paper will show the results of the sand risk integrated study which evidences a certain degree of strength heterogeneity in the Hollin formation. According to the stresses and strength information, the risk of sand production in open hole horizontal wells is not negligible for high drawdown values ≥1000 psi. The risk of sanding decreases for lower drawdown (in the range from 500 psi – to 1000 psi), but cannot be totally excluded due to rock strength heterogeneity. Critical DD of 1000 psi and Safety DD of 500 psi is finally concluded. A simulation in a vertical well was done with no sanding risk. This result is in agreement with the Oglan 2 dir well test, which did not observe sand production with a maximum DD of ~700 psi. Since the development of the field is planned by the drilling of horizontal wells the risk of sand should be Included in planning of the completion method.
No depletion has been considered through all the sand risk analyses, as strong aquifer support is believed to keep pressure almost at the virgin level. The effect of the water production in producing sand is considered since increasing water cut could increase the sanding potential. The second section describes the selection criteria used to evaluate different technologies for downhole sand control which involves sand failure characteristics, particle size distribution, well condition, reservoir and fluid characteristics, plugging risk, erosion risk and well productivity to identify the optimal downhole sand control.
This paper provides the complete workflow applied for sanding evaluation necessary for the development plan of the field. The results of geomechanical analyses and modeling showed indeed that the mechanical behavior of the Hollin reservoir in Oglan Field is somewhat different when compared to information available in the Oriente Basin literature, so the technical information detailed in the paper is useful for future development and correlations of nearest fields.
Ultra Deepwater wells are commonly characterized by a narrow margin between pore and fracture gradients. Eni experience presented in this paper covers different experiences through two HPHT wells located in Mediterranean offshore; the first well already drilled, hereafter called well “A”, and the second well called “B”, planned to be drilled in the next future at the date of this document preparation.
During the planning phase the high reservoir pressure expected in the well “A” has requested to design it with the use of a continuous circulation technique to ensure safe operation having higher margin between dynamic mud weight and fracture gradient. It was planned the use of e-cd™ (eni circulating devices) system, installed for the first time ever on a drilling ship with the 6 5/8” DPs.
However, during the well execution phase, the pressure gradients profile resulted even more challenging than expected with the pore gradient almost equal to the fracture gradient.
Despite the unexpected gradients profile, all the planned exploratory targets drilled have been reached working on the well feasibility limits applying the most advanced drilling technology. An accurate real time monitoring system and an adequate organization have permitted to achieve this important target. The results were obtained with the efforts done by the whole company’s team who has analysed in “real time” all the drilling events, the geopressure gradients development and the well responses through a prompt management of change process. At well TD, the static mud gradient applied resulted lower than the pore gradient but, thanks to the use of continuous circulation technique, the dynamic mud gradient on bottom hole was maintained higher than the pore gradient but lower than the fracture gradient for safely drilling the well.
Eni experience on well “A” has opened the door to design the new challenging well “B”. This well plan was to re-enter a HPHT well temporary abandoned for pressure management constraints. The approach to drill this new well was to implement the advanced technologies used in the well “A”, such as the continuous circulation but combined with the MPD (Management Pressure Drilling) technique for the first time applied on a DP drilling ship. This allowed for extra safe margin to achieve the targets by continuously controlling the dynamic mud gradient on bottom hole with the use of surface backpressure and by promptly control the virtual mud weight fluctuations while drilling operation. To mitigate the overall exposure to the risks and to overcome all the possible drilling scenarios, a technical group operating in real time was formed to be ready for taking any decision in case of well constraints.
A huge amount of data is recorded during well operations, ranging from rig sensors to lithological information, drilling reports, and equipment records.
Usually the use of these data, particularly those acquired through rig sensors, is limited to control in real time drilling operations. However, all these records are highly valuable for future wells engineering and planning. This paper describes how the combination of these data sets increases their value and creates practical analyses for well problems investigation, performance enhancement, and ultimately supports cost reduction by anticipating and reducing risks.
The use of “big data” solutions creates significant analytics combining multiple data types (sensors and reports) both on single well and group of offset wells. Particularly the interpretation of rig sensor data through the automatic recognition of operating sequence, when put together with other data sources, including traditional reports (DDR, DMR, DGR, etc.), provides a much higher granularity than traditional reporting.
Every operation is accurately measured through objective and detailed KPIs (ROP, tripping speed, weight to weight, connection time, etc.). Technical and performance issues are easily evaluated allowing a better understanding of their root causes, anticipating and avoiding the occurrence of these problems in the next wells and measuring activities and operations potential improvement.
As a further output, it supports future well planning by comparing equipment performance or operational sequences with other wells. It provides a full set of benchmark statistics on the main drilling indicators available and directs the selection of the optimal/best solution for the next wells.
A tangible economic benefit of this approach, measured on a real application, can be expressed in the range of 5% to 8% of overall well expenditure.
Furthermore, this innovative use of rig sensor data is supporting contractual strategy definition (impartial evaluation of the performance), operations monitoring (addressing drilling parameters giving the best performance) and training (providing a rich knowledge base for well engineers).
We present a case history of 3D modeling and backstripping analysis of the paleo-topographic surface developed in the Po Plain–Northern Adriatic region during Latest Messinian sea-level drop occurred in the Mediterranean region, with special emphasis on the reconstruction of the paleocoastline position. The model results from the integration of 2D seismic interpretation, backstripping and numerical modeling at a lithospheric scale using TISC program (Garcia-Castellanos et al., 2002; 2003) considering both the loading of the Plio-Pleistocene sediments and the regional amount of sea-level drop reported in the literature (Ghielmi et al., 2013, Rossi et al., 2015).
The best fit between facies distribution maps and the resulting modeled coastline has been reached imposing a sea level drop of only 850m. This value is quite different from the ca.1500m calculated for the Mediterranean basin, thus suggesting that the Po Plain-Adriatic basin was an isolated sub-basin from the eastern Mediterranean, protected from a complete desiccation by a sill located in the Southern Adriatic Sea.
Thanks to this fruitful cooperation between industry and academia, it is now possible to describe the entire 3D basin geometry and the facies distribution during the Latest Messinian time, including the expected position of potential exploration targets provided by coarse-grained deltaic complexes presumably developed at the mouths of riverine systems during the Messinian Salinity Crisis and then
sealed by Pliocene marine marls.
The aim of this modeling is to apply the 3D Backstripping technique to restore the vertical position of the Latest Messinian surface in the Po Plain-Northern Adriatic Foredeep (PPAF). Commonly the backstripping technique removes (in several steps) different units and water load effect from the total subsidence; part of subsidence is therefore caused by tectonic driving force.
The way in which the studied basin reacts mostly depends on the isostatic response of the lithosphere.
Staltari, Daniele (Eni Angola) | Urdaneta, Jose (Eni Angola) | De Azevedo, Orlanda (Eni Angola) | Pellicanò, Dario (Eni E&P) | Ripa, Giuseppe (Eni E&P) | Cauende, Cesar (Sonangol E. P.) | Nasrallah , Mena M. (M-I Swaco) | Aye , Yeneapre A. (Schlumberger) | Djouli , Lere B. (Schlumberger) | Adeolu, A. I. (Schlumberger) | Magloire , Bafakan A. (Schlumberger) | Kumar, Amrendra (Schlumberger) | Gadiyar, Bala R. (Schlumberger) | Parlar, Mehmet (Schlumberger)
High-inclination wells targeting multiple reservoir sections interlayered with reactive shales, relatively low fracture window, and prolonged well suspension without well cleanup were some of the challenges that needed to be addressed to ensure completion integrity and well productivity. This paper presents the measures taken during the design and execution phases to address the project challenges, along with an evaluation of completion integrity and well performance. Analysis of the downhole-gauge data is detailed for one of the wells as an example, illustrating the importance of downhole gauges in the completion. Introduction Block 15/06 West Hub, in deepwater offshore Angola, is geographically in the Lower Congo Basin in water depths from 3,937 to 4,593 ft (Figure 1). Tertiary (Miocene, Oligocene, Eocene, and others) and Lower Cretaceous intervals contain the main oil-bearing rocks in this basin. This field-development plan targeted the Tertiary Lower Miocene turbiditic channel that is among the mostprolific reservoirs in this basin. However, production from this channel also creates sand-production issues because of its highly unconsolidated sand. The reservoir of this channel consists of multiple sand bodies separated by shales. Channel-sand permeabilities are in the range of 500 to 1,000 md, while pressure and temperature are at the normal gradient of 0.43 psi/ft (4,200 psi) and 1.6
Drago, Antonio (Eni E&P) | Vignati, Emanuele (Eni E&P) | Bergamaschi, Barbara (Eni E&P) | Calzari, Marinella (Eni E&P) | Morales, Fernando L. (Schlumberger) | Fumey-Humbert, Frederic (Schlumberger) | Toyas, Christos (Schlumberger)
The aim of an ongoing implementation of a global production management system is to support an operator in its continuous efforts to improve its affiliates' oil and gas field operations. The main objective of production operations is the maximization of the project returns, which involves the optimization of well production rates, increased of reservoir recovery, and the reduction of the associated expenses. This objective can only be achieved through the effective use of accurate information about the production system's performance (including its reservoirs, wells, and surface and process facilities). Due to the massive amount of information generated daily in oil and gas fields, specialized software tools are essential for data gathering, cleansing, and storing and for meaningful dissemination, consumption, and analysis of the data to aid decision making. Aware of this critical need, starting in 2008, Eni launched an ambitious program to implement a production data management system (PDMS) that allows specialists to properly perform well and hydrocarbon production accounting, run specific workflows to correctly analyze the information, and effectively support the operations in several key affiliates around the world. The interconnected system has proved to be very valuable for strategic planning and informed decision making, considering the size and the remoteness of the operations and the need to assure that operations in the assets are carried out in the most efficient way possible. The current scope of the PDMS global program includes completed implementations for 12 affiliates and the monitoring of more than 4,000 wells. This paper describes the program's objectives, the achieved benefits, and the vision on the way forward. The paper also addresses some of the main problems encountered during the execution and enumerates the main lessons learned.
Staltari, D. (Eni Angola) | Urdaneta, J. (Eni Angola) | Barradas, O. (Eni Angola) | Pellicano’, D. (Eni E&P) | Ripa, G. (Eni E&P) | Fernandes, P. (M-I SWACO) | Cauende, C. (M-I SWACO) | Sonangol, E. P. (M-I SWACO) | Nasrallah, M. M. (M-I SWACO) | Aye, Y. A. (Schlumberger) | Djouli, L. B. (Schlumberger) | Adeolu, A. I. (Schlumberger) | Magloire, B. A. (Schlumberger) | Kumar, A. (Schlumberger) | Gadiyar, B. R. (Schlumberger) | Parlar, M. (Schlumberger)
Most of the deep water reservoirs in Angola are weakly consolidated sands, requiring sand control, and openhole gravel packing is one of the most widely used sand control techniques in the area, Block 15/06 being no exception. High inclination wells targeting multiple reservoir sections interlayered with reactive shales, relatively low frac window, and prolonged well suspension without well cleanup were some of the challenges that needed to be addressed to ensure completion integrity and well productivity. This paper presents the measures taken during the design and execution phases to address the project challenges, along with an evaluation of completion integrity and well performance. Analysis of the downhole gauge data is detailed for one of the wells as an example, illustrating the importance of including downhole gauges in the completion.
Arata, F. (Eni S.p.A.) | Cardola, P. (Eni S.p.A.) | Costanzo, C. (Eni S.p.A.) | Grilli, F. (Eni S.p.A.) | Valdisturlo, A. (Eni E&P) | Burt, J. (Schlumberger) | Chinellato, F. (Schlumberger) | Denichou, J. (Schlumberger)
Nikaitchuq is an oil field on the North Slope of Alaska that has been developed with more than 60 extended-reach wells having 6,000-ft to 18,000-ft-long horizontal sections. The main reservoir interval in Nikaitchuq corresponds to a shelfal lobe composed of two main sand bodies, encased in structural depressions. The development scheme consists of waterflood line drive with horizontal producers and water injection wells located side by side. The majority of the development wells were designed with a single horizontal trajectory undulating between the two main sands bodies in counter phase with the related water injectors.
To be successful, such challenging well design requires accurate geological modeling, effective geosteering capabilities, and sensible well data acquisition. The objective of the approach here described is to correctly reconstruct the reservoir geometry by integrating numerous data and information coming from such long horizontal wells. However, data and information that have originated from different sources have different levels of accuracy. A thorough data quality assessment is a mandatory step in any data integration exercise. Hence, all information available in each horizontalwell section was reviewed in detail and cross-examined. Bed boundary mapping data interpretation via different inversion processes and log and image interpretations (such as gamma ray, neutron density, resistivity, density images, deep azimuthal electromagnetic data) were compared, validated, and integrated in the 3D geological model to perform a very precise reconstruction of reservoir internal geometry.
Such accuracy in modeling was not only aimed at enhancing the precision of volumes in place and resource estimates, but it was also a prerequisite for the successful drilling of the subsequent wells during the field development.
The novelty of the approach consisted in the integration of density image logs, bed boundary mapping data, and resistivity modeling results to derive accurate information on the reservoir geometry at a scale useful for 3D modeling. This use of data goes beyond common practices.