The objectives of the paper are to use the Basrah NGL gas processing project in the Basrah Gas Company JV (BGC) to demonstrate best practice application of industry solutions and appropriate technology selection, aligning with project value drivers whilst managing technical and non-technical uncertainties in decision making.
In mid-2018 contracts were awarded for the Basrah NGL gas processing hub in Southern Iraq that will set the competitive cost and schedule benchmark for new gas plants in Iraq. Embracing Shell and industry experience to deliver a standardized and replicable design was a key priority for the project team and JV partners. Technology selections were evaluated against project value drivers to support robust decision making for current and future operations, and contracting strategy selected considering synergies across the portfolio through bundling and building on in-country experience.
Two trains of 200 mmscf/d each have been awarded in the first development phase, however future expansion requirements are much simplified with the facility designed to be expandable to 5 replicated trains providing a total 1000 mmscf/d capacity in line with the upstream gas production forecast. The benefits of standardisation and replication lock in further cost and schedule savings for subsequent gas processing trains and continue to lower unit development and operating costs. In line with the future plans for the facilities, pre-investments were made for major infrastructure investments including gas and LPG export pipelines and high voltage power supply.
The BGC NGL processing train design is flexible to the range of gas qualities prevalent in Southern Iraq. Technology selections have been appropriately made to consider current and future requirements both in terms of ethane and LPG recovery but also acid gas removal and Sulphur recovery solutions. In the case of Sulphur recovery, a Shell and-Paques developed, Thiopaq technology is selected to provide the most capital efficient flexible solution, whilst also providing ease of scale-up to higher recovery rates as the upstream gas supply becomes progressively more sour (with higher H2S content) over time.
Al-Murayri, Mohammed T. (Kuwait Oil Company) | Kamal, Dawoud S. (Kuwait Oil Company) | Al-Mayyan, Haya (Kuwait Oil Company) | Shahin, Gordon T. (Shell) | Shukla, Shunahshep R. (Shell) | Ten Berge, Anke B.G.M. (Shell)
Following encouraging results from laboratory experiments, simulation studies and a one-spot EOR pilot for the Raudhatain Zubair (RAZU) reservoir in Kuwait, a multi-well pilot is planned in the near future. A combination of high temperature (90°C), in-situ brine salinity (>250,000 ppm) and divalent ion concentration (>20,000 ppm) make implementation of Alkaline Surfactant Polymer (ASP) flooding in RAZU quite challenging. The presence of a ‘Tar Mat’ interval in the pilot area further complicates pilot design. This paper outlines some of the risk mitigation measures for a successful ASP pilot.
Laboratory experiments were performed to evaluate different polymers for improved thermal stability and to obviate the risk of polymer precipitation at the producers. Based on long-term thermal stability studies and producer scaling considerations, HPAM/ATBS based polymer was chosen over HPAM -based polymer. The original formulation which was used in the one-spot EOR pilot required 3.5% co-solvent to overcome surfactant separation at optimal salinity. Several alternative alcohols were tested and finally an appropriate co-solvent that gave adequate performance at 1.5 wt% was selected to reduce cost and logistical requirements. Additionally, optimization experiments were conducted to de-risk emulsification potential of produced oil by reducing the concentration of the injected surfactants. Finally, experiments were carried out to characterize the nature of the hydrocarbon and rock in the ‘Tar Mat’ interval to evaluate the risk versus reward of perforating it in the pilot area.
This is the first time, to our knowledge, that ASP injection is being considered in a reservoir in such a harsh environment due to combination of high temperature, salinity and divalent ion concentration in formation brine. The presence of a ‘Tar Mat’ interval further complicates pilot design. The successful execution of this pilot will push the envelope of ASP deployment in other challenging reservoirs worldwide.
In 2014, an R&D project was intitiated to develop an innovative technological solution to improve the performance and reliability of Deepwater Gulf of Mexico assets. The objective was to increase the life expectancy of Miocene and Lower Tertiary water injection (WI) wells, several of which had suffered a severe loss of injectivity within only a few years of completion.
Before scoping out the project, an internal study was conducted to compile and analyse the available data. The root problem was identified as an accumulation of formation solids inside the lower completion; principally fine matrix sand that had been pulled in from the reservoir. These formation solids are normally stationary during steady injection, but can be mobilized during shut-ins (maintenance, pump problems, environmental conditions, etc.) due to powerful transient flow effects such as back-flow, cross-flow and even water-hammer. Eventually, enough solid fill can accumulate inside the lower completion as to diminish the injection rates. At this point the operator must consider some very expensive options such as to sidetrack or re-drill a new injector well.
The obvious solution to this problem was to find a way to prevent the fine material from getting inside the completion. The challenge was to do so while sustaining high injection rates, with no loss of injection pressure or requirement for additional horsepower. Therefore, the goal of the project was to find a practical, efficient method of stopping the formation material from entering the lower completion during a shut-in cycle. To achieve this, a new flow control device (FCD) and completion system was developed with intrinsic non-return valves (NRV) that are designed to prevent any back-flow or cross-flow during the shut-ins. Also, depending on well conditions, the system will minimize the damaging effects of water-hammer: rapid, high-amplitude pressure cycles that can occur during a sudden stoppage of flow.
Mullins, Oliver C. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Forsythe, Julia C. (Schlumberger) | Chen, Li (Schlumberger) | Achourov, Vladislov (Schlumberger) | Meyer, John (Deep Gulf Energy) | Johansen, Yngve Bolstad (AkerBP) | Rinna, Joachim (AkerBP) | Winkelman, Ben (Talos) | Wilkinson, Tim W. (Talos) | di Primio, Rolando (Lundin) | Elshahawi, Hani (Shell) | Canas, Jesus (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Zuo, Julian Y. (Schlumberger)
Asphaltenes can be dispersed in crude oils in 3 different forms; molecules, nanoaggregates (of molecules) or clusters (of nanoaggregates); these forms are codified in the Yen-Mullins model and relate to the extent of solvency of the asphaltenes in the crude oil. Many reservoir studies are used here to show the systematic behavior of the specific asphaltene species in crude oil and the corresponding magnitude of the asphaltene (and viscosity) gradients. In addition, the specific asphaltene species is related to the chemical origin controlling asphaltene onset pressure (AOP) and tar formation and depends on 1) the quality of the live crude oil solvent for asphaltenes and 2) the concentration of asphaltenes. Elevated quantities of solution gas of a reservoir crude oil significantly reduce the solvency of asphaltenes in crude oil. For low concentrations and/or good solvency, asphaltenes are dispersed in crude oils as molecules with small gradients (unless there are large GOR gradients). For moderate concentrations and/or moderate solubility, asphaltenes are dispersed as nanoaggregates with intermediate (gravity) gradients of asphaltenes. With large concentrations and/or poor solvency, asphaltenes are dispersed as clusters with very large gradients in reservoirs. These crude oils can also exhibit higher asphaltene onset pressures and/or phase separated bitumen or tar in the reservoir depending on the origin of asphaltene cluster formation. Secondary gas charge into oil reservoirs can yield tar and/or a high AOP. The effect of biodegradation on these factors is also discussed. The systematics presented here are helpful in understanding a variety of reservoir concerns associated with asphaltenes.
This paper provides the validation test results of preheat sequence applied to induction motors at two Test Facilities and offshore application for operation in the Gulf of Mexico.
Although the objective of preheating Induction Motors (IM) is to lower the viscosity of the lubricant oil by 2 orders of magnitude (from 1000 cP to 10cP) for extending Electric Sumersible Pump (ESP) run life, this paper is exclusively focused on motor preheating results.
The motor is energized with low voltage at a frequency of 120Hz maintaining the voltage low enough in order to keep the supplied shaft torque under the system's breakaway torque; thus the shaft never spins. The Medium Voltage Drive (MVD) is a Variable Frequency Drive output power determines heat rate that is adjusted to obtain temperature slope of 1°F/min specified by the project.
The motor is modeled electrically and magnetically through Finite Element Analisys (FEA) to estimate its power losses; the motor internal temperatures can be predicted by the Motor-CAD (Computer-Aided Design) thermal model which is calibrated by winding resistance change and skin tempeperature measurement.
The systems for validation were: First test facilities: 1500hp Induction Motor coupled to a pump and driven with a 2500hp MVD Second test facilities: 1500hp Induction Motor coupled to a dyno and driven with a 2500hp MVD. Offshore: Five 1500hp ESPs driven with 2500hp MVD each.
First test facilities: 1500hp Induction Motor coupled to a pump and driven with a 2500hp MVD
Second test facilities: 1500hp Induction Motor coupled to a dyno and driven with a 2500hp MVD.
Offshore: Five 1500hp ESPs driven with 2500hp MVD each.
The results at first and second test facilities and offshore in the Gulf of Mexico demonstrate the preheat sequence can be successfully implemented in the field by using existing MVD with little software changes in order to apply low voltage at 120Hz without spinning the rotor. The stator current and induced current on the rotor make motor internal temperature (including lubricant oil) to rise achieving different temperature slopes. Temperature slopes vary in function of applied motor current (there was no need of overpassing motor nominal current on any test), motor thermal capacity, initial motor temperature, and external temperature.
All tested motors are very similar and was found that Keeping heating power at around 34kW, winding temperature rise can be achieved at a rate of 1.52°F/min at an initial temperature of 38°F and 1.2°F/min at an initial temperature of 148°F. Temperature rise rate at the motor air gap (actually filled with oil) and bearings location can also be predicted by the motor thermal model.
The required preheating time is previously calculated to reach less than 10cP viscosity of lubricant oil to guarantee safe startup without the occurrence of bearing spin; otherwise bearing friction torque overcomes the T-ring retaining torque causing bearing(s) damage.
When the need of preheating the induction motor of electric submersible pumps installed in deepwater applications was identified, there was no clear means to make it possible. This was the first time that concept was applied and successfully implemented in the field.
A second milestone was to preheat the motor with the MVD without adding equipment. Among five potential methods for preheating the motor, the selected scheme worked as expected with minimum MVD software changes.
Brunei offshore platforms are home to hundreds of maturing wells in need of ongoing interventions. Offshore operations in Brunei face several obstacles, (i.e., weather conditions, ageing platform facilities, limited lifting capability, and limited workspace), as well as tight work schedules that make the work challenging.
As with other mature fields, the Brunei wells need high efficiency operations to reach production targets. These challenges can be addressed with a purpose built compact semi-submersible vessel (CSS) with dynamic positioning (DP 2) equipped with a full catenary coiled tubing unit, a pumping unit with flowback capability, and a dedicated slickline unit.
Dual hull design with a compensated gangway increases the weather working envelope of the vessel. The coiled tubing catenary system with a reel turntable helps enable coiled tubing unit flexibility during rigup and work under varying weather conditions. Integration of the vessel and the coiled tubing unit helps enable a 24/7, 365 day work unit.
Average downtime caused by weather decreased by up to 10%, averaging 8.5% in 2 years, compared to previous work vessels with an average between 15 and 18% downtime because of weather.
Further efficiency improvement is gained through use of fit for purpose equipment. A 35 ton jacking frame helps enable injector and pressure control equipment stack up to be made up, function, and pressure tested offline. A small footprint flowback package was introduced that reduced the total number of lifts from 12 to 6, saving two hours lifting time per rig up/down. Overall rigging up time was reduced by approximately 20% with the improvements to equipment setup.
The reduced equipment necessary on the platform enabled wireline and coiled tubing to operate concurrently. This enables 24 hour wireline interventions to be executed offline more efficiently. Time savings for intervention completion were approximately 62%. This setup enables more efficient use of existing resources to complete the work scope.
The setup, collaboration, and execution on the vessel demonstrate the opportunity for improvement, which is important under current industry conditions, and help enable a cost effective yet robust operation.
A new approach based on the similitude principle is used to evaluate the effect of fluid viscosity on pump performance. A well validated CFD technique of the entire stage of a mixed flow pump including the secondary flow path is utilized to develop this method. Simulations are carried out at different fluid viscosities representing the pump performance in laminar as well as turbulent flow regimes. The non-dimensional parameters such as head coefficient (Ψ), flow coefficient (ϕ) and rotational Reynolds number (Re) are utilized to characterize the pump performance. The head coefficient data for all viscosities collapsed to two separate lines when represented as a function of
Yeh, Tzu-hao (Shell) | Jennings, James (Shell) | Cakici, Deniz (Shell) | Guerra, Jose Chavarria (Shell) | Durand, Melanie (Shell) | Williams, Britt L. (Shell) | Chen, Tianhong (Shell) | Casillas, Rebecca (Shell) | Jain, Vivek (Shell) | Li, Ruijian (Shell) | Bai, Taixu (Shell)