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After production startup on Lean and Rich Gas Fields in Algeria, some of the reservoirs have shown a continuous pressure decline that was affecting the real production potential of many wells, due to the surface wellhead flowing pressures approached the network pressure resulted from the central process facility (CPF) operating pressure. In this regard a "do nothing" production forecast was calculated and the results were showing that many wells would be most likely equalized with the flow line pressure within months, which is expected to casue significant production losses due to wells instability operating at critical condition, followed by eventual shut ins that will jeopardize the original production targets. Moreover, the flow regime in the pipeline network connected to the CPF was creating instability in the hydrocarbons treatment process as well.
The initial action was the installation of a Local Boosting System (LBS) at manifold level on lean gas wells, encompassing 5 compressors, connected in parallel to manage the maximum production at a given inlet pressure, compressing the volume up to 86 bar. The system was designed for lean gas with the possibility to theoretically handle all the associated liquids. In contrast, for rich gas wells a positive displacement Multi-Phase Pump was installed at well head level to confirmin the potential to lower down the flow line pressures by up to 25 bars, however the application was limited for rich gas wells only with a Gas Volume Fraction (GVF) below 95%.
Therefore, in order to have the flexibility to treat both rich and lean gas wells (up to 100% GVF), a new Multi-Phase pump system has been identified by comparing the different boosting systems performance and analyzing well by well production scenarios. The multiphase twin screw pumps are the central part of these complex systems designed to allow a wide range of operating conditions. It would be possible to decrease the suction pressure by reducing the hydrocarbon treated volume in order to manage production decline and subsequent changes on gas-liquid ratios due to further reservoir depletion. The success of this new pumps application relies on the installed liquid management system, which is designed to work together with the pumps and allowing the necessary temperature reduction whenever they reach the operating limits that would compromise the final performance and eventually halt the pumps.
With two systems successfully installed in different configurations, all the wells involved have been able to produce with an optimized bottom hole draw down to extend their productive life with the current flow line pressures constrain. In addition the stabilization of flow rate by well also brought the required stability at the CPF process. This paper is intended to provide high level technical details of the new system (liquid management and pumps) tailored to handle and treat both lean and rich gas wells, and highligh the impact on the total field production, which is the first application in Algeria and probably worldwide
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.
Performance evaluation of water injector wells is usually done by injection and fall-off tests. However, the well test analysis of fall-off tests is often challenging because of the interaction of two immiscible fluids in the reservoir.
The paper presents a field example where six different fall-off tests, separated by large time intervals in a long injection sequence were analysed for a well injecting water in an oil reservoir. In order to reproduce the fluid interaction in the reservoir, it was essential to consider the relevant impact of temperature on the injected fluid viscosity in the near-wellbore zone due to the cold-water injection. At the wellbore scale, a temperature reduction of around 95 degree Celsius was observed with respect to the virgin reservoir temperature, which in turn led to an increment of viscosity of the injected fluid by approximately four orders of magnitude. The analysis of each fall-off showed a radial composite behaviour, with the two radial flow stabilizations depending upon the different mobility of oil and water, while the radius of interface depending upon the cumulative volume of injected water. The interpretation provided the key reservoir characteristics (formation capacity in the water-invaded and virgin oil zone, transient injectivity index, static reservoir pressure, skin, etc.) and allowed an assessment of the well injection capability and its change with time in the reservoir. Within Eni, repeated fall-off analysis in a well is becoming a powerful and cheap tool for efficient waterflood management.
Besides providing key parameters for reservoir characterization and a dynamic picture of near wellbore region, the paper highlights the peculiarities of a fall-off test and the way reliable outputs can be achieved. It demonstrates how it is crucial to consider temperature related viscosity variations and how it is the key driver for achieving accurate well test results.
The injection of fluids in hydrocarbon reservoirs is a widely used method to achieve higher recovery factors and increase recoverable reserves. Particularly, water injection in oil reservoirs represents an important secondary recovery method in deepwater oilfields operated by Eni due to the low associated costs.
Pipeline in-line 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 hydro-mechanical 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 re-create the line elevation, profile with limited
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)
Most of the deepwater reservoirs in Angola are weakly consolidated sands, requiring sand control, and openhole gravel packing is one of the most widely used sand-control techniques for producers; Block 15/06 is no exception (Hecker et al. 2004; Whaley et al. 2007; Pena et al. 2013; Menezes et al. 2013; Bingyu et al. 2016). 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.
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.
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).
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.
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 sealevel 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.
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.