Performance of a new three-phase (3-P) flow measurement system is presented using multiphase flow loop data. The system consists of two currently available products: an optics-based flowmeter and a near-infrared (NIR) water-cut meter. The measurement capability and performance of a combined system comprising two robust and field-proven technologies under realistic flow conditions is demonstrated for the first time. The new 3-P flow measurement system represents a viable alternative for subsea multiphase flow measurement and can also be used on offshore platforms, onshore as well as downhole, in single-zone or multizone applications.
The flowmeter system relies on three main measurements: bulk velocity and sound speed measured by the optics-based flowmeter, and water-cut measured by the water-cut meter. The velocity measurement is a robust measurement based on turbulent flow and is not affected by upstream flow conditions. The water-cut measurement is based on NIR absorption of water and oil molecules, and therefore, is immune to water salinity and the presence of gas (such as free gas, gas in solution, and oil foaming). Total flow rate is calculated using the bulk velocity measurement; liquid holdup and density of the mixture are obtained by introducing the mixture sound speed and the water-cut measurements into a flow model.
The results of the multiphase flow loop test demonstrated that the new flow measurement system is capable of resolving total volumetric flow rates as well as phase volumetric flow rates in a broad gas-volume-fraction (GVF) band. Furthermore, mixture density can be successfully calculated from the flow model and, as a result, the mass flow rates can also be determined. The test data also confirm that the water-cut measurement is not affected by foaming issues and associated density variations. The test results are discussed in detail in the paper.
The new flow measurement system offers several advantages. The flowmeter can be installed in any orientation and does not require recalibration. Its nonintrusive and fullbore features mean no permanent pressure loss, and high resilience to erosion and corrosion. The nonnuclear water-cut meter measures water cut in the broad GVF spectrum and is not affected by challenging flow conditions, such as slug flow. Installed inside a wellbore, an optics-based flowmeter can provide reliable flow measurement for the life of that well with no significant drift in signal.
Abdussamie, N. (Australian Maritime College) | Haase, M. (Australian Maritime College) | Sartipi, K. (Australian Maritime College) | Ojeda, R. (Australian Maritime College) | Amin, W. (Australian Maritime College) | Thomas, G. (University College London)
The commercial Computational Fluid Dynamics (CFD) code STAR-CCM was used to simulate the dynamic behaviour of a tension leg platform in extreme weather conditions. The numerical results of surge motions and tendon tensions were compared against the measurements acquired in model tests. The fullscale CFD simulations were then conducted on the basis of the settings performed in modelscale simulations. Both model-and full-scale surge motions and tendon tensions predicted by CFD were in good agreement with the measurements. Using CFD results, it was revealed that the component of the vertical wave-in-deck force caused a slam force on the platform followed by tendon slack situations in the down-wave tendons.
The Wheatstone and Iago gas fields, located approximately 110 km northwest of Barrow Island in the Carnarvon Basin, are developed through a common subsea and offshore platform infrastructure. The production forecasts for the Wheatstone Project are generated using reservoir simulation models for both fields coupled to a shared production network model. This ensures the appropriate representation of boundary conditions on the production system, such as well back-pressures. Typical forecasting workflows in a greenfield environment include running experimental design (design of experiments) to generate probabilistic forecasts of field responses. However, conventional experimental design workflows are based on simulations of a single field and are often completed without coupling the reservoir model to a production network model.
This paper will discuss the improvements to conventional simulation workflows made by the Wheatstone Reservoir Engineering Team. These refinements, which enabled running experimental design with both reservoir models coupled to a production network model, allowed responses to be generated and reviewed at the project level. This approach accounted for field interference through the production network and afforded the opportunity to understand the production interactions and relationships more accurately and thereby establish a vantage point for improved optimisation. The improvements were necessary to overcome some of the commercial and in-house software limitations constraining the workflow and results.
This type of simulation workflow had not been achieved to this extent previously within Chevron Corporation. The approach described here allowed the direct generation of project level responses, such as timing of future drilling campaigns, which would not have been practical or reliable otherwise. Future improvements of this modelling workflow will consist of standardising the workflow within the Corporation, using it for history matching later in life as well as decreasing cycle time on more routine simulation work.
Rezazadeh, M. (Northern Territory Department of Mines and Energy) | Hattum, J. van (Northern Territory Department of Mines and Energy) | Marozzi, D. (Northern Territory Department of Mines and Energy)
The production of conventional onshore oil and gas in the Northern Territory began in 1983 from the Palm Valley gas field, Amadeus Basin South of Alice Springs. Up until 2010the industry relied on conventional oil and gas development technology albeit with substantial technological advances over time. In recent years the focus of the industry has shifted to unconventional resource exploration, particularly the highly prospective shale gas resources in the McArthur and Georgina Basins. Current estimates indicate that the Northern Territory has more than 200 trillion cubic feet of prospective unconventional natural gas resources in six basins. The technologies and techniques to explore and develop petroleum resources from deep shale are innovations on technologies and practices employed for exploration and development of conventional resources with revolutionary consequences, particularly in North America.
SRA is one of the well platforms in a marginal gas field operated by PT Pertamina Hulu Energi Offshore North West Java (PHE ONWJ). SRA production is evacuated to the SA platform via a 6.3 km 8" Main Gas Line (MGL), which has been in operation since 2002. Changing corrosiveness of the fluids produced at SRA after the MGL integrity and in 2015 several leaks were detected. Repair by conventional means or replacement was deemed uneconomic. A study was therefore initiated to evaluate the technical and economic feasibility of low capital cost and low maintenance cost technologies to rehabilitate pipelines in marginal fields with high CO2 content without increasing safety or environmental risks.
In the appraisal stage, several technology options were considered and a thermoplastic pipe was selected as the preferred alternative compared to traditional rigid carbon steel pipeline. The assessment process started with a pipeline technology review, followed by technical compatibility/acceptance study, a check of commercially available pipe sizes and a comparison of total installation cost, installation schedule, and operation-maintenance considerations. The decision was facilitated by Expected Value Decision Analysis. The expected value of each option included CAPEX, OPEX, NPV, and all quantified aspects and risk.
The thermoplastic plastic pipe assessed is a flexible pipe for shallow water consisting of polyethylene (PE) internal liner, annular ring steel strip armor, and PE outer sheat. The PE inner liner is nearly hermetic, but allows traces of gases such as CH4, CO2, H2S, and H2O to permeate through. These permeants tend to accumulate in the flexible pipe annulus. A slight overpressure above atmospheric develops in the pipe annulus driving the gases to the end fittings where they are vented, preventing excessive pressure build up.
Additional weight is required for on bottom stability of thermoplastic pipe to be laid in Offshore North-West Java area. The installation spread will be using the available Pipe Lay Barge blanket contract for the Pipeline Repair and Replacement Program.. Even though some advantages of flexible pipe cannot be obtained in this project, such as additional weight required and lay barge usage instead of DP2, the selected concept is still the most economic compared to other options. The CAPEX is 10% less than carbon steel pipe. OPEX reductions can be achieved by reducing pigging operations and eliminating In-line Inspection (ILI) and chemical injection.
This paper presents a critical review of literature on bore and well failure mechanisms and rates, and conceptualisations of probable reservoir-aquifer failure pathways. The objective was to gain a better understanding about bore and well induced inter-aquifer connectivity and the potential consequences to groundwater resources. This comprehensive review included Australian and international literature on onshore conventional oil and gas wells, water bores, coal seam gas wells and coal exploration bores. Failure mechanisms and rates were discussed for the entire well life cycle. Reservoir-aquifer failure pathways were then conceptualised based on the failure mechanisms and risk analyses considering the likelihood of failure and detection, repair and potential impacts on hydrogeology.
The operator’s exploration of natural gas in coal seams within the Gloucester Basin, New South Wales (NSW), Australia presents technical challenges accessing and producing the gas economically while meeting stringent environmental standards. These standards are more stringent than those applied to petroleum exploration and production in other states of Australia. This paper presents hybrid downhole microseismic and microdeformation monitoring technologies applied in a vertical CSG well.
The Gloucester Basin is an area of complex geology with high horizontal stresses, some faulting/compartmentalization, dipping bedding planes, and multiple thin bands of coal strung out over hundreds of meters. Regulations have all but stopped some companies exploring for CSG in NSW. This is despite large identified petroleum reserves, importation of gas from interstate to supply the local market, and a NSW chief scientist and engineer report stating CSG carries risks no greater than any other of the extractive industries and that those risks are manageable (
Providing confidence that hydraulic fracture geometries are relatively confined to target coal seams and do not grow upward into beneficial groundwater aquifers is a primary concern. A hybrid downhole microseismic and microdeformation array was deployed to monitor fracture stimulation of a vertical CSG exploration well at Gloucester to provide more accurate insight into overall fracture height coverage. Downhole microseismic and microdeformation technologies complement one another by providing unique, far-field determinations of hydraulic fracture geometry. This is one of the first times downhole tiltmeters have been used to monitor microdeformation caused by hydraulic fracturing of a CSG vertical well in Australia and the first time either technology has been used in NSW. Results from work performed in November 2014 show relatively confined fracture height growth with good agreement between microseismic and microdeformation data. Low microseismic event magnitudes (-3.9 to -2.1 Mw) recorded indicate no interaction with faulting in proximity to the target well. In addition to a vertical fracture component, microdeformation data indicated presence of steeply dipping fracture components on all zones. This data, combined with high fracture gradients (well above overburden) observed with each stage, and increasing in shallow intervals, confirmed the prediction of complex fractures, especially for fracture zones shallower than 600 m.
Hybrid diagnostic results confirmed the 1D mechanical earth model (MEM) built for the target area and both fracture complexity and main fracture azimuth were generally as predicted. The complex nature of the fracture propagation prevents uncontrolled vertical growth, which gives confidence that hydraulic fractures are not growing into the vicinity of shallow beneficial aquifers.
In gas processing facilities, the minimum metal temperatures (MMT) in process equipment and piping are usually observed during highly transient depressurization operations ("blowdown"). The MMT usually sets the material of construction and can have a huge impact on project costs and ultimately project viability.
To explore this issue we use a recent case study that considers the design from Pre-FEED through to Final Investment Decision of a gas processing facility. During pre-FEED, the most widespread methodology for designing the depressurization system, based on idealized equilibrium volumes, was applied. This showed that extremely low metal temperatures could be expected in nearly all parts of the processing facility. To avoid material embrittlement, large vessels and piping would have required expensive stainless steel construction for ~80% of the facility.
As a result, a more detailed methodology for accurate assessment of MMT during depressurization was applied. This methodology involves a detailed representation of the processing facility using accurate dynamic models and requires a greater level of analysis and more effort. It does, however, account for different system pipe and vessel dimensions and wall thickness; as well as system elevations, points where condensate liquid may accumulate, drainage and the location of blowdown valves. The results predicted much more accurate MMT at each location throughout the processing facility.
Having identified specific locations of concern, the design team developed targeted solutions addressing all predicted issues whilst minimizing capital expense. Savings were achieved by optimizing material selection and other critical design specifications. By utilizing the detailed blowdown methodology throughout the design cycle only 30% of the facility is being constructed from stainless steel.
We conclude by reviewing the different methods for depressurization system design, their relative merits and discuss how designer engineers can identify systems that require more thorough attention.
In Kuwait, the traditional approach to Field Development has been to drill wells, whether Vertical or Horizontal, Single or Dual, with completions dedicated to either Production or Injection. However, as increasingly more wells are being drilled to develop the stacked reservoirs, surface infrastructure is growing in complexity with regard to Production Flowline routing, Gathering Facility location, Satellite Manifold placement, Water Injection distribution lines routing, and access road construction. Also, since the reservoir stack is a combination of areally extensive Carbonates overlying shale & channel sand sequences, optimum surface locations of Injectors for one reservoir is now increasingly conflicting with the optimum surface locations for the Producer of another reservoir.
The North Kuwait team presented options that could reduce the requirement for excessive wellbores for both new Producers and Injectors. One of which is the utilization of a single wellbore to both Produce Oil from one reservoir and Inject Water into another reservoir simultaneously. This novel approach utilized the most popular Dual Completion equipment. Rather than dually produce or inject from separate reservoirs or layers, production & injection are achieved simultaneously, from the same wellbore, through successive tubing strings. Tubing movement calculations were made to ensure that the resultant axial tubing forces exerted by simultaneously injecting cold water and producing hot reservoir fluid would not cause the Dual packer to prematurely unset.
This unique completion has several advantages which include the production acceleration from an adjacent reservoir/layer that would have been postponed for the life of the Injector and the elimination of the drilling of a new producer to access the oil from an adjacent reservoir/layer to the target injection zone.
Fruhen, Laura (Center for Safety, University of Western Australia) | Wang, Lena (Center for Safety, University of Western Australia) | Griffin, Mark (Center for Safety, University of Western Australia) | Finnerty, Dannielle (Center for Safety, University of Western Australia) | Jorritsma, Karina (Center for Safety, University of Western Australia) | Boeing, Alexandra (Center for Safety, University of Western Australia)
Practitioner views on good safety leadership constitute implicit leadership theories. Themes in the descriptions of best practices in safety leadership, illustrate what behaviours are seen as most effective and may be most beneficial in leader development. Paricipants of this study (n=112) completed an online survey consisting of open questions regarding their views on safety leadership and multiple choice items concerned with how these behaviours may best be trained. Based on a model of safety leadership that contains four behaviours (Leveraging, Energising, Adapting, and Defending), the responses were analysed to identify themes. The analysis indicated that participants' responses particularly reflected three of the leadership behaviours namely Leveraging, Energising, and Defending. Adapting, which contains future oriented behaviours related to learning was not frequently indicated. Participants' responses also showed a preference for a blended approach for safety leadership training consisting of online and face to face learning. The results provide insights into the similarities and discrepancies between academics and practitioners' views on the conceptualization of safety leadership and can inform leader development.