The objective of this paper is to showcase the strategic integration of TAKREER Ruwais Refinery within its existing Ruwais Refinery - East (RR-East), Ruwais Refinery Expansion - West (RR-West), upcoming CB&DC (Carbon Black & Delayed Coker project) facilities and also with other operating companies (OPCOs). The paper highlights how this integration enhances synergy amongst all OPCOs which leads to overall reduction in capital costs, GRM maximization, Energy Optimization and therefore leading to value maximization.
TAKREER'S project team judiciously conducted detailed technical and economic feasibility studies to ensure refinery configuration and its integration within TAKREER and with other OPCOs not only meet TAKREER's vision in becoming a World Class diversified Refining Complex but also realize the overall objective of ADNOC group of companies.
High Benzene Reformate streams from RR (East) and ADRD (TAKREER Abu Dhabi Refinery) are upgraded in RR(West)'s Bensat unit to produce Low Benzene Reformate. LPG from RR (East) & RR (West) is processed in RR (West) to maximize High octane Alkylate production replacing hazardous MTBE.
TAKREER'S CB&DC project would convert low valuable heavy bottom of the barrel feedstocks like Slurry oil from RR (West) & Vacuum Residue from RR (East) into high valuable specialized products i.e., Anode grade Coke, Carbon black, etc while ensuring Zero Fuel Oil generation from the Refinery.
Crude oil is sourced from ADCO and Natural Gas used as fuel is sourced from GASCO. Utilities i.e., Steam and water are produced as captive from within, power is sourced from TRANSCO. Nitrogen is sourced from ELIXIER. TAKREER's main product i.e. High valuable Polymer Grade Propylene product is exported to BOROUGE as feedstock to BOROUGE's Polypropylene units. TAKREER's upcoming state of the art Propane De-Hydrogenation Unit would not only utilize Propane & LPG streams from RR (West) & RR (East) but also use Propane stream from GASCO to produce Propylene. Similarly, Carbon Black product would be exported to BOROUGE. Liquid Sulphur product and LPG is sent to GASCO. To minimize loss of products or minimize downtime within TAKREER as well as across OPCOs, facilities are available for mutual sharing of streams like Hydrogen, Ethane Rich Gas and Butane streams can be shared within TAKREER'S RRE, RRD & CB&DC facilities.
Ethylene recovery and conversion of Ethylene & C4s into Propylene is an innovative and unconventional approach to increase Propylene production. TAKREER’ s upcoming PDH unit is the world's first facility in the world to be installed within Refinery complex. Similarly Carbon Black production from low value low-value Slurry oil is another novel idea towards strategic integration with other OPCOs.
Thus strategically integrated facilities contribute to overall reduction of capital costs and improves Operating margin thereby leading to increase in profitability.
The potential for gas hydrate production is always present in deep water operation. It will cause hazardous impact if gas hydrate plug formed during drill stem testing. This paper takes a case from south china sea, with about 1500 meters water depth gas field, to describe hydrate prediction and prevention during drill stem testing.
This paper will discuss:
The method to predict what depth the gas hydrate may be formed in the testing string. Procedure optimization to reduce the risk of gas hydrate Key technique to prevent gas hydrate formation The result of execution
The method to predict what depth the gas hydrate may be formed in the testing string.
Procedure optimization to reduce the risk of gas hydrate
Key technique to prevent gas hydrate formation
The result of execution
The study indicated it is viable technique to predict gas hydrate formation by simulating fluid flow in testing string, as well as hydrate inhibitor selection and the amount of inhibitor can be simulated and optimized. The procedure of one flow period and one build-up period reduced the operational risk to form gas hydrate. Downhole methanol injection and closely production monitor prevented gas hydrate production. As a result of this practice, six times of DST has been successfully implemented in deep water gas field in south China sea. The well productivity and fluid sample has been accurately obtained for future overall development plan.
The result of this study are most applicable to DST design in deep water gas field, however, they also may also be appropriate for shallow water DST.
This Mega Project involves re-development of a producing oil field from 4 newly constructed aritifical islands. The new production facilities, well manifolds, pipe racks, buildings are being constructed in a modular form to reduce on site work activities. The project's main challenges included: Long field life (>30 years) Aggressive phased development schedule Large capacity equipment / facilities Limitations on fabrication yard capacities Remote site working conditions Brownfield construction environment (resulting from interfaces with an early production system)
Long field life (>30 years)
Aggressive phased development schedule
Large capacity equipment / facilities
Limitations on fabrication yard capacities
Remote site working conditions
Brownfield construction environment (resulting from interfaces with an early production system)
South East (SE) is one of the major assets in Abu Dhabi Company for Onshore Petroleum Operations Ltd (ADCO)'s portfolio. Until 2013, SE was producing from fields (Asab, Sahil and Shah) and 2 new fields (Qusahwira & Mender) which were under development. The initial operation philosophy for the new fields was to have a centralized operation organization with necessary support functions at Asab and to deploy only the facility operating resources at respective fields.
Due to the change in company strategy, SQM (Shah, Qusahwira & Mender) has been spin-off from SE and a new organization was put in place while Qusahwira (QW) was moving from commissioning to production in 2013.
SQM Operation Management Team (OMT) has initiated a business transformation program to ensure required business processes were in place for the new organization to seamlessly integrate the development asset in to a producing portfolio. Assigned task force acted as a program management office and process champions were allocated within the major Level 1 (L1) processes for its implementation. Finally SQM has successfully integrated into the existing organization through implementation of necessary business process within the asset.
The paper will discuss the detailed methodology, challenges faced and the change management initiatives implemented during commissioning to production transition.
Davila, Ytalo (Shell Global Solutions International B.V.) | Grigoriadou, Katerina (Shell Global Solutions International B.V.) | Olfos, Tomas (Shell Global Solutions International B.V.) | Schoon, Lodi (Shell Global Solutions International B.V.) | Infantino, Melina (Shell Global Solutions International B.V.) | Last, Tim (Shell Global Solutions International B.V.) | Mitkidis, Georgios (Shell Global Solutions International B.V.) | Martavaltzi, Christina (Shell Global Solutions International B.V.)
Commercially available post-combustion CO2 capture technologies are based on aqueous amine solutions. One of the main cost drivers of such processes is the energy required for solvent regeneration. Most advanced technologies currently claim regeneration energies between 2.7 and 3.2 MJ/kg of CO2 for separation of CO2 from a Natural Gas Combined Cycle (NGCC) power plant flue gas. A system comprising a precipitating carbonate-based solvent has been claimed to have energy consumption well below 2.5MJ/kg of CO2. Here, the concept is evaluated to quantify its potential to bring down the cost of CO2 capture. A process model is developed based on correlation of available thermodynamic data to perform heat and material balances and to define the process operating window. Furthermore, experiments were carried out in a bench scale unit of 25kg/d (2.77x10-4 kg/s) CO2 capture capacity to demonstrate the integrated process concept. Finally, a techno-economic evaluation is performed based on the design of a commercial scale unit of one million tons per year (33.07 kg/s) CO2 capture capacity. The results indicate that the technology has not only higher energy requirements than originally claimed, but also higher capital cost than state of the art amine based systems. Thus, it is decided to stop further development of the technology.
One of the main safety issues incorporates the risk of gas explosion. Active safety measures have been developed to prevent the incidents from leading into gas explosions. Though progress has been made, high overpressures associated with the gas explosion have still remained challenging. Lack of feasible solutions to protect the building ventilation openings from overpressures higher than 0.3 bar (4.4 psi) have resulted in designers trying to cope with the risk with plant layout design and forcing safety specialists to accept the risk to a certain degree.
Advances in gas explosion simulation have made it notable that blast wave will enter the reinforced building even from a small opening in a wall, typically an air vent. Even placing the air vent outside the line of sight of the blast wave will not solve the problem due to complex propagation and reflection pattern of the blast wave. Also manifestation of high overpressures has become more evident.
This paper discusses the various new possibilities offered by blast protection products for higher than 0.3 bar overpressure and multiple consecutive explosions protection. Attention has been given to the protection of ventilation openings in buildings as sufficient mitigation of explosion risks is required in order to sustain the operability of critical functions in emergency.
The main objective of this paper to is to discuss the recent finding on the formation anisotropy and lateral heterogeneity in the different hydrocarbon fields of onshore Abu Dhabi. The study was focused on Thamama and Wasia groups, mainly related anisotropy and spatial heterogeneity of the geomechanical poperties for reservoir characterization. This would have an impact on the stress variation and the definition of potential "sweet spots" for well placement optimization and identification of suitable completion methods.
The 1D Mechanical Earth model (MEM) is a description and quantification of rock elastic and strength properties, in-situ stresses and pore pressure as a function of depth, referenced to a stratigraphic column. The available wireline logs of several existing wells, including the compressional and shear slowness, stonely, bulk density, and gamma ray were used to compute log-derived elastic parameters, strength properties and stress components. Rock mechanics laboratory core plug tests were performed to calibrate the log-derived mechanical properties. Anisotropic modelling was applied to understand the anisotropy in elastic properties and horizontal stresses.
Integrating the 1D-MEMs indicate that Onshore Abu Dhabi Geomechanical properties (elastic and strength) and in-situ stresses vary laterally and vertically. Further, several mechanical layering and horizontal stress anisotropy can be identified. These results imply that the Wasia and Thamama reservoirs are susceptible to different fracturing mechanisms. Hence different fracture and faults sets can be predicted within the highly anisotropic deformation zones.
These findings significantly impact the exploration play concepts, where lateral variations are anticipated. This also applied to the production and development, where the stress barriers control the stimulation and completion strategies.
Miraglia, Salvatore (Eni S.p.A. - Upstream & Technical Services) | Borromeo, Ornella (Eni S.p.A. - Upstream & Technical Services) | Maragliulo, Chiara (Eni S.p.A. - Upstream & Technical Services) | Rodrigues, Juan (Eni S.p.A. - Upstream & Technical Services) | Sartorio, Dario (Eni S.p.A. - Upstream & Technical Services)
With the aim of building environments of deposition (EOD) maps supporting the prediction of the reservoir quality in the Mishrif Formation investigated in the subsurface of the Zubair field, sedimentary facies distribution and reservoir internal architecture were defined through integration of 3D seismic interpretation with well data (core facies, biostratigraphy, petrophysical parameters and log-derived facies obtained extending the log character of the different core facies to the non-cored wells).
The workflow comprised the sedimentological core study, the seismo-stratigraphic interpretation tied to the well stacking pattern and the environment of deposition mapping including the interpretation of attribute volumes derived from seismic inversion (porosity and frame flexibility facies volume based on the internal Eni approach CaSRC -Seismic Reservoir Characterization for Carbonates- which put into relationship the rock physic parameters to the pore structure).
Mishrif Formation consists of shallow water, bioclastic carbonates deposited in a well-developed carbonate ramp system. Geometrical evidences observed on seismic allowed to depict the evolution of the ramp passing through a main phase of aggradation, a subsequent step of progradation and, finally, a stage of aggradation-progradation. For each identified system tract, thickness maps were computed and depositional settings distributed as inner, middle and outer ramp domains. Each domain is represented by a group of facies characterized by its own configuration of porosity and pore types. Porosity is excellent in rudist bearing shoal facies deposited in the middle ramp setting and poor in mudstone and wackestones of the outer ramp. The inner ramp domain is characterized by packstone with poor to moderate porosity, improved at the very top of the Formation by diagenetic alteration associated with subaerial exposure.
Once established the relationships between facies types, environments of deposition and porosity, the EOD maps were utilized to estimate the porosity distribution within each system tract. In this view, the interpretation of the volumes derived from the seismic inversion were included in the mapping process to refine the outlining of the boundaries between depositional domains characterized by different porosity configurations.
The approach proved to be very useful in predicting the distribution of facies and related reservoir properties in areas of the field poorly controlled by well-data.
Chakravarty, Krishna Hara (Center for Energy Resources Engineering (CERE), Department of Chemical and Biochemical Engineering, Technical University of Denmarak) | Fosbøl, Philip Loldrup (Center for Energy Resources Engineering (CERE), Department of Chemical and Biochemical Engineering, Technical University of Denmarak) | Thomsen, Kaj (Center for Energy Resources Engineering (CERE), Department of Chemical and Biochemical Engineering, Technical University of Denmarak)
Condensation, vaporization and volumetric changes are well-studied phenomena that create differences between the properties of oil at reservoir and surface condition. But similar changes in effluent brine properties have not received the same attention. This study attempts to analyze variations in properties of the effluent brine at reservoir and surface conditions.
Various research groups have conducted water flooding experiments. Concentrations of the effluent brines have been reported. In this study speciation properties of these brines have been reanalyzed. The Extended UNIQUAC Model was used to precisely compute the brine speciation. Calculations was conducted both at surface and reservoir (pressure, temperature) conditions. And possible release of fines that remained unaccounted in previous studies was explored.
The calculation at high temperature and pressure showed that during water flooding, significant amounts of fines were released from the core plug. But with a decrease in temperature and pressure (i.e. at surface condition) these produced fines got dissolved in the effluent water. Thus the produced fines were no longer observable at room temperature. A significant increase in the solubility of anhydrite with decrease in temperature is found to be the principal reason for the dissolution of produced fines. The previously unaccounted fines were observed for the following types of experiments: Rock Type: Chalk, Limestone and Dolostone Coreplug Type: Outcrop and Reservoir Coreplug Flooding Type: Spontaneous imbibition and water flooding experiment EOR Strategy: Low salinity, Smart waterfloods and Advanced Ion Management Rock Origin: Middle East, North Sea and United States
Rock Type: Chalk, Limestone and Dolostone
Coreplug Type: Outcrop and Reservoir Coreplug
Flooding Type: Spontaneous imbibition and water flooding experiment
EOR Strategy: Low salinity, Smart waterfloods and Advanced Ion Management
Rock Origin: Middle East, North Sea and United States
Furthermore a good correlation was observed between the amount of produced fines and the reported amount of oil recovery. Herein it was observed that production of fines increased significantly when the composition of injected brine was significantly altered. The interaction between the injected brines and the existing brine could have led to formation of mobile fines. This trend was found congruent with incrementing oil recovery.
The calculations show that brine speciation at reservoir condition is significantly different from that at surface conditions. During EOR waterfloods significant amounts of fines are produced which are closely correlated with the increments in oil recovery. These produced fines have previously been unaccounted for. The Extended UNIQUAC model can be used to accurately calculate the amounts of these fines.
Multiphase flow meters (MPFMs) are being widely employed in the oil and gas industry for a higher rate test frequency in the producing wells and for continuous production monitoring. But after the installation and before it provides services, a MPFM experiences a lengthy process that is comprised of meter calibration, settings configuration and wellhead sampling for liquid density checking. To accomplish this process is often challenging in offshore fields due to the adverse weather conditions and the high costs of offshore activities. That has hindered the MPFM commissioning activities in many Aramco offshore fields and consequently affected the testing requirements.
A MPFM is an intelligent metering device which is very sensitive to the fluid's PVT properties, fluids densities, H2S and CO2 contents. A typical calibration of a MPFM in Aramco offshore fields often requires taking fluid samples from each individual well for the fluid density check and determination of mass attenuation of oil due to the fluid density variations in a field. An offshore MPFM often covers the testing requirements for all 6 to 8 producers on a platform. Hence this method always takes a long time to take wellhead fluid samples for completing the calibration process of a single MPFM, and tends to lag far behind their planned commissioning schedule.
In 2013, thirty seven new MPFM were installed in 37 different platforms covering more than 122 wells in one Aramco field. A commissioning and calibration campaign was launched early this year with a different approach after carefully analyzing the PVT properties of the produced fluids. In this approach the typical calibration work was first performed on 3 wells, and then the same settings and parameters were copied and uploaded as a batch to those remaining MPFMs covering other 119 wells in this field. This method significantly reduced the time for marine boat support. Furthermore, those 119 wells are being remotely flow tested in a batch via Supervisory Control and Data Acquisition (SCADA) to verify if any further adjustment is required. Due to H2S and CO2free in the produced fluids, and the almost constant liquid densities throughout the area in this field, the accuracy of the MPFM measurement can't be compromised by taking this process. The paper describes a new method that significantly reduced the total time for the 37 MPFM calibration and commissioning jobs and saved the costs.