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flow rate
Proposing a Method for Performance Evaluation of a Designed Two-Phase Vertical Separator and a Piston Pump Using Computational Fluid Dynamics
Dastyar, Zahra (Department of Mechanical Engineering, Shahid Chamran University of Ahvaz) | Rabieh, Milad M. (Department of Chemical Engineering, Shahid Chamran University of Ahvaz (Corresponding author)) | Hajidavalloo, Ebrahim (Department of Mechanical Engineering, Shahid Chamran University of Ahvaz)
Summary Designing and testing effective separators is a time-consuming task that requires sophisticated laboratory equipment or expensive field tests. Computer-aided simulation could be a fast and affordable alternative if the method demonstrates effectiveness and reliability. This work implements a method to simulate a hybrid separator by considering variable outlet boundary conditions caused by a piston pump. This method consists of a novel mesh generation method and a two-phase unsteady-state computational fluid dynamics model that enables full-scale simulations and shows acceptable results that comply with experimental data. Furthermore, the simulation is repeated in several gas/liquid ratios and piston speeds, leading to a correlation to predict the separation efficiency of similar designs. As expected, the results revealed that the pressure drop would increase and separator efficiency would decrease by increasing the piston speed. The influence of the gas/liquid ratio on the pressure drop and separation efficiency was negligible.
- Europe (0.93)
- Asia (0.68)
- North America > United States > Texas (0.46)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
Exceptional Length of Coring Recovery in a Very Loose Sand or Unconsolidated Formation in South Natuna Sea Block B at 8-1/2" Hole Section with a Conventional Full Closure System
Wales, Benny Richard (NOV Inc.) | Aribowo, Triadi Herwasto (NOV Inc.) | Hartanto, Daru Mulyo (NOV Inc.) | Darmawan, Kurnia (NOV Inc.) | Putranto, Heru (Medco E&P Natuna Ltd) | Panjaitan, Julianta (Medco E&P Natuna Ltd)
Abstract The South Natuna Sea Block B field is located in the waters of the Riau Archipelago and is a large and fragmented PSC that covers a number of oil and gas fields in the Natuna Sea, of which a few are currently operated by Medco E&P Natuna Ltd. Coring Service is one of the processes that is required by Medco E&P Natuna Ltd. for unconsolidated formations as the target reservoir zone. Unconsolidated formation is very challenging to core, especially with the standard conventional system, as the core could slide and slip off from the inner barrel assembly of the Standard Conventional System while pulling out of the hole while the whole coring assembly is in progress. A Full-Closure System technology with a Double catcher assembly (Clam Shell Catcher and Spring Catcher as the main component) is necessary to address the problem. The full closure system technology, which was created specifically to catch any unconsolidated formations, has gained widespread acceptance for its effectiveness in a variety of fields, particularly in Indonesia. Even when the Full Closure system is assembled and run in the hole, anomalies like core jamming and milling the core are difficult to detect at the surface gage while coring is taking place at unconsolidated formations. The challenge is further increased by the 90-foot length of the core that must be retrieved in a single-run in order to save cost by reducing the number of trips. This plan goes against the best advice or rule of thumb given by the majority of coring services, which stated that when coring, especially in an unconsolidated formation, a shorter length of barrel is highly recommended, such as per joint or only 30 feet to be done in one run, for example, for a Total of 3 (three) × 30 feet to retrieve the entire target of 90 feet, in order to avoid any unforeseen anomalies. Since vibration always increases the likelihood of core jamming, a shorter core barrel could potentially cause less vibration while coring is taking place. If this happened, the core would then be milled. Therefore, a shorter barrel always presents a lower risk of losing precious data samples if core jamming and core milling anomalies ultimately occur undetected. This paper is made to inform, demonstrate, and discuss how Full-Closure System technology and certain key procedures that are strictly followed and monitored could mitigate the potential hazards or risks mentioned to Successfully Core the 90-foot core target in one run at an Unconsolidated formation and be the first to ever do it in that length, especially in Indonesia.
- Asia > Indonesia (0.70)
- Europe > Norway > Norwegian Sea (0.25)
- Asia > Vietnam > Gulf of Thailand > Southwest Vietnam (0.24)
Enhancement of Drilling Effectiveness Through Lean 6 Sigma Methodology
ALAlawi, A. S. (Petroleum Development Oman, Muscat, Sultanate of Oman) | Peter, J. (Petroleum Development Oman, Muscat, Sultanate of Oman) | ALKindi, A. (Petroleum Development Oman, Muscat, Sultanate of Oman) | ALAdawi, H. (Petroleum Development Oman, Muscat, Sultanate of Oman) | Husaini, N. (Petroleum Development Oman, Muscat, Sultanate of Oman) | ALAlawi, M. (Petroleum Development Oman, Muscat, Sultanate of Oman) | AL Nuumani, M. (Petroleum Development Oman, Muscat, Sultanate of Oman)
Abstract Objectives/Scope This paper highlights how PDO's Well Engineering Directorate adopted the Lean 6 Sigma methodology (using inferential statistics for problem solving) to improve the effectiveness of drilling 9.5/8" Multi-Stage Inflatable Packer Collar (MSIPC) tool. Furthermore, we explain how this data-driven technique helped us understand factors that influence drilling with this tool. Methods, Procedures, Process The Lean 6 Sigma methodology was implemented on multiple projects in Well Engineering. The term "Sigma" is used in statistics as an indicator of the degree of process variation. 6 Sigma is a structured approach that consists of five phases; Define, Measure, Analyze, Improve, Control (DMAIC). Drilling the MSIPC tool is a repetitive operation but there is significant variance in its execution as drilling can vary from 30 to 240 minutes. There have been many failed attempts to optimise this process because they depended on people's experience only which boiled down to a trial-and-error approach. In the "Define" Phase we outlined the business case and formed a team, sponsored by senior management. We then collected data from all jobs executed between 2019 and 2020 and visualised the data in different chart types to better understand process variation. In the "Measure" Phase we conducted a workshop with all stakeholders, mapping the process end-to-end, identifying the main factors affecting the process. A Process Capability Diagram was used using Minitab (a statistics software), to assess the process baseline performance. We found that more than 70% of the jobs exceeded the upper specification limit of 60 minutes. We developed a Control Chart, which proved the process to be instable. Results, Observations, Conclusions In the "Analyze" Phase we conducted a graphical analysis (e.g., Matrix Plot, Main Effect Plot, Box Plot, etc.) and hypothesis testing (correlation and regression analysis) to determine which of the input parameters had a significant impact on the process time. The main findings were: There was no significant relationship between the MSIPC drilling time and depth. There was a significant relationship between the MSIPC drilling time and Bit Type, Weight on Bit (WoB), Rotation per Minute (RPM), and Flow Rate. Multiple regression analysis was then used to determine the relationship between significant input parameters and their combined impact on the result. From this, we were able to optimise the process parameters as follows: WoB should be more than 4 kdaN, surface RPM should be 30-35, and Flow rate should be 1.5 m3/min. We were also able to conclude that PDC bits perform better for than Tricon bits. In the "Improve" Phase we implemented the parameters the determined from the analysis on 10 wells and saw a significant process improvement. The average time to drill MSIPC reduced from 120 minutes to 55 minutes.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
Slot-Jet-Isolate: A Next-Generation Explosives-Free Remedial Technology
McWilliam, Gary (TotalEnergies Norge AS, Stavanger, Norway) | Lucas, Alex (TotalEnergies Upstream Danmark ??A/S, Copenhagen, Denmark) | Gaskin, Keith (TitanTorque, Aberdeen, United Kingdom) | Jacobs, Lars (TotalEnergies Nederland, The Hague, Nertherlands) | Macpherson, Steve (CNOOC Petroleum Europe Limited, Aberdeen, United Kingdom) | Ullbrand, Björn (FS Dynamics, Staffanstorp, Sweden) | Molony, Dave (TotalEnergies Nederland, The Hague, Nertherlands)
The Slot-Jet-Isolate (SJI) system is a newly developed, explosives-free and low-footprint remedial technology designed for full flexibility in the remediation and testing of challenging annuli for a variety of applications. An extensive full-scale testing programme was executed with the support of industry sponsors to demonstrate the effectiveness of the Slot, Jet, Isolate (SJI) concept. Testing was performed on fullycemented casings to confirm the ability of the slotting system to develop a hydraulic connection with the annulus for even the most challenging annuli not previously within the envelope of traditional systems. The learnings have been applied to further enhance the power of the slotting blades and robustness of the tool, and determine operational limits prior to initial field deployment. Following the success of the first phase of testing, the tool was deployed for an operator in the UKCS to successfully slot casing and displace oil-based mud from the annuli of four subsea wells prior to the setting of environmental plugs, removing the need for explosives and successfully conducting operations more efficiently than the established approach. Since this first application, the tool has subsequently also been run offshore Netherlands to slot casing to facilitate washing and removal of annular solids prior to pulling casings during P&A operations. The potential of the technology for future fully-rigless deployment via the use of Coiled Tubing was also confirmed. This paper will report on how the SJI system was developed with the help of effective collaboration between industry partners to accelerate its maturation from concept to successful field deployment in only 18 months, and will further demonstrate how this flexible technology may also be configured for applied casing recovery applications, in addition to its future intended application to annular cement remediation for well plug and abandonment (P&A). 2 SPE-215590-MS
- North America > United States (1.00)
- Europe > United Kingdom > Scotland (0.28)
Abstract Most of interpretation and analysis procedures developed for pressure transients acquired by multi-probe and packer-probe wireline formation testers (WFTs) are used to conduct are based on the slightly compressible fluid of constant viscosity and compressibility. Hence, these interpretation and analysis procedures apply for oil and water bearing formations. There is a concern that the interpretation/analysis methods based on the assumption of slightly compressible fluid may not be applicable in the case of testing a single-layer or a multi-layer gas zone(s) with the effects of nonlinear gas properties including non-Darcy flow for multi-probe or packer-probe wireline formation testers. In the literature, to the best of our knowledge, there is no a comprehensive study investigating the validity of the above stated assumption for the interpretation of WFT pressure transient data in gas zones. In this work, variety of cases considered for investigating the effect (or sensitivity) of non-linear gas flow on the pressure transients from multi-probe and packer-probe wireline formation testers (WFTs). These effects include gas gravity, variation of gas viscosity and compressibility with pressure, non-Darcy flow, position of active (flowing) and observation probes, mechanical skin and radius of skin (or invaded) zone, and reservoir heterogeneity in the vertical direction. A three-dimensional r-θ-z single-phase-gas fully-implicit finite-difference model for a limited-entry vertical well has been developed for the purpose of this investigation. The results show that for multi-probe wireline testers, the sink (or the flowing) and horizontal probe pressure responses are highly affected by the effects of the non-Darcy flow and invaded zone, while the vertical probe pressures are mainly influenced by the properties of the uninvaded zones with non significant non-Darcy flow effect. For packer-probe testers, similar results are obtained. Both synthetic cases are presented to confirm the theory and procedures developed in this work.
- Europe (0.68)
- North America > United States > Texas (0.46)
- Asia > Middle East > Turkey (0.29)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Slickline Deployed Fibre Optic Cable Provides First Ever Production Profile For High Temperature Gas Well
Berry, S. (M Webster Expro Group Ltd.) | Dirya, D. (TotalEnergies E&P UK Ltd) | Cowie, G. (TotalEnergies E&P UK Ltd) | Hooker, A. R. (TotalEnergies E&P UK Ltd) | Innes, R. (TotalEnergies E&P UK Ltd) | Gray, R. (TotalEnergies E&P UK Ltd)
Abstract Distributed Fiber Optic Sensing (DFOS) allowed us to continuously gather flow profile information from a high-temperature high-rate gas well. The objective of this case study is to demonstrate that Distributed Temperature and Distributed Acoustic data, thermal inversion modelling can be used to produce a Production Flow Profile in an environment where conventional production logging was not possible. Cerberus modelling was performed, concluding there was a risk of tool lift whereby a conventional production logging tool string is deployed during flowing states. Therefore, a 0.181" diameter fiber slickline was selected to allow a continuous measurement over the accessible perforation interval at multiple rates without the risk of tool lift. A program consisting of a memory production log, run by standard slickline cable to acquire a shut-in profile looking for potential crossflow was followed by a DFOS run to gather DAS and DTS data during shut-in and flowing rates of 30 MMSCF/Day and 60MMSCF/Day. Near real-time DTS data was analyzed to aid in the evaluation of temperature stability at each rate change, and DAS data was processed at the wellsite to enable transmission to and analysis onshore. DFOS data was successfully acquired and processed at wellsite and transmitted to town allowing for monitoring of data quality and decision making during the intervention. A complete suite of DAS/DTS data was acquired over the perforated interval at multiple flow rates, facilitated by monitoring near real-time transient behavior which aided in decision making for rate changes. Thermal inversion modelling and DAS analysis were performed, providing evidence of crossflow during shut-in and variations of flow allocation during the differing flow rates. It was observed that surveying at lower flow rates would have provided a different flow profile compared with normal operating rates. As a result of deploying DFOS, data could be acquired at more realistic rates. Through performing thermal inversion of the DTS data and analysis of the DAS data a more accurate flow profile was achieved. This is the first profile to be acquired in the field for use in reservoir simulation and production modelling. This will result in more accurate reservoir and well optimization. This is a layered sandstone reservoir with a two-thirds production drop since start-up in this well. Approximately 80% of production was produced from one zone and surveillance to plan remedial action was essential to maintain economic production.
- Geophysics > Borehole Geophysics (0.89)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (0.56)
Abstract In two planned large-scale CCS projects in the Netherlands – Porthos and Aramis – depleted gas fields will be used for CO2 storage. These fields are characterized by low reservoir pressures. For example, the Porthos project is planned to inject into a field with a reservoir pressure below 20 bar. Project design and operational philosophy need to be specifically tailored to the storage reservoir properties in order to avoid excessively low temperatures when injecting into such fields. This paper describes how these challenges were addressed for the Porthos project. In most CCS projects, a CO2 mixture is transported in a surface network at high pressure and ambient temperature and injected into an aquifer. At the high reservoir pressure typical of aquifer storage the CO2 stream remains in dense phase or supercritical conditions in the entire system. This dense phase transport strategy is not feasible for the P18 field since the bottomhole pressure (BHP) is around 25 bar at the required injection rates. At this low pressure, CO2 will exist in two-phase conditions which results in very low temperatures of −10 °C. These low temperatures are unacceptable since they may result in hydrate formation in the reservoir and well integrity issues. A specific operating philosophy and project design was developed to avoid unacceptably low temperatures. At a reservoir pressure below 50 bar, CO2 is injected in gas phase in the pipeline and wells. Once the reservoir reaches a pressure of 50 bar the pipeline pressure is increased to 85 bar to achieve dense phase conditions. The well is operated in two-phase conditions but due to the higher BHP well temperatures are now acceptable. However, if CO2 is transported at ambient temperature the injection flow range per well is very narrow and the required project injection range cannot be met. This is addressed by using the heat of compression to heat the CO2 stream and insulating the pipeline to achieve elevated arrival temperature. Without these specific choices, safe injection into the P18 field would not have been possible.
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Sleipner Vest Field > Sleipner Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Sleipner Vest Field > Hugin Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Sleipner Vest Field > Draupne Formation (0.99)
- (59 more...)
Hydrogen Storage in Depleted Gas Fields: A North Sea Case Study
Looijer, M. (Shell Global Solutions International B.V., The Hague, The Netherlands) | Ahmad, I. (Shell India Markets Private Ltd, Bangalore, India) | Kathel, P. (Shell Global Solutions International B.V., The Hague, The Netherlands) | Filomena, C. (Shell Global Solutions International B.V., The Hague, The Netherlands) | de Borst, K. (Shell Global Solutions International B.V., The Hague, The Netherlands)
Abstract This paper presents a case study on a near-shore gas field in the Dutch North Sea for a seasonal storage scenario. A subsea development was considered, connected by pipeline to an onshore processing facility. Reservoir simulations were carried out to model the mixing of the hydrogen with the in-situ natural gas and to estimate the composition of the back-produced stream and its variation during and between the individual cycles. The required sizing of the processing facilities was determined through process models, and the pipeline sizing through a hydraulic assessment. The development considered new wells, which were designed to deliver the assumed hydrogen production rate at the end of a production cycle when contamination is highest. The investment and operational costs of the complete facility were estimated as well as emissions of the storage operations. The study enhanced the understanding of the technical scope and technology gaps; as well as the economic, environmental, and energy performance of underground hydrogen storage. It highlights main cost drivers and delivers insights into the re-purposing potential of the existing infrastructure. An example insight gained from the study was that the disposal (or utilization) of the waste stream from gas separation could pose a real challenge particularly in an offshore environment, given its intermittent character, the highly variable and partly unpredictable composition, its large flow rate, and its near-atmospheric pressure when using a Pressure Swing Adsorber for separation.
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.46)
- Europe > Netherlands > North Sea > Dutch Sector > West Netherlands Basin (0.99)
- Europe > Germany (0.89)
Fervo Energy has shown that fracturing can be used to build a geothermal heating system in hot, hard rock. During a 37-day test at its Project Red test site, the Houston company produced as much as 63 L/s (998 gal/min) of water heated to 336 F. By pumping water from an injection well through fractured hot rock to a producing well, it heated enough water to generate up to 3.5 MW of power, according to a company release. In a world where demand is commonly measured in gigawatts, that's not much, but it is more than double the highest flow rate from tests going back decades. And unlike those earlier tests, the company has a clear path to heating higher volumes and lowering the cost. "I think this is just a big moment for both our company, but also the industry at large, to finally have this proof point where we can deliver commercial levels of permeability and flow rates for these wells," said Jack Norbeck, co-founder and chief technical officer for Fervo.
Fervo Energy has shown that fracturing can be used to build a geothermal heating system in hot, hard rock. During a 37-day test at its Project Red test site, the Houston company produced as much as 63 L/s (998 gal/min) of water heated to 336°F. By pumping water from an injection well through fractured hot rock to a producing well, it heated enough water to generate up to 3.5 MW of power, according to a company release. In a world where demand is commonly measured in gigawatts, that’s not much, but it is more than double the highest flow rate from tests going back decades. And unlike those earlier tests, the company has a clear path to heating higher volumes and lowering the cost. “I think this is just a big moment for both our company, but also the industry at large, to finally have this proof point where we can deliver commercial levels of permeability and flow rates for these wells,” said Jack Norbeck, co-founder and chief technical officer for Fervo. The idea of injecting water through hot rock has been around for decades as a way to create enhanced geothermal systems (EGS), but this is the first time someone has achieved this level of flow and is moving next to create a group of geothermal wells for commercial generation. Fervo has taken methods developed to extract oil and gas from ultratight rock and shown they can be used to do something quite different. “Overall, there’s nothing really surprising here—they used a pretty standard shale frac design and observed pretty similar performance from what you would see in a shale play. Or at least, what you’d expect if you used a shale well as a long-term water injector and circulated fluid over to a neighboring production well,” said Mark McClure, chief executive of ResFrac, a reservoir modeling and consulting firm, in a blog post. This fracturing-based option poses a challenge to EGS researchers who live in countries where completions using oil industry fracturing techniques are not an option. “The EGS community has conventionally been focused on ‘stimulating natural fractures,’ and this has led them to use fracture designs that would be considered suboptimal, from the perspective of oil and gas field experience,” McClure said. What Fervo has done is show that fracturing can be used to get past a barrier blocking EGS development using current fracturing technology. “The breakthrough is that someone actually had the guts and organization to go out and do it,” McClure said. Those at Fervo, though, have little time to celebrate the milestone as they focus on improving those methods to economically produce geothermal energy. “In successfully completing this project, we have demonstrated that no major technical barriers exist to deploying horizontal EGS in similar meta-sedimentary or igneous formations to temperatures of approximately 400°F,” according to a Fervo paper. That feat was recognized by a leader at the FORGE test site, which is also doing EGS research and development with substantial financial support from the US Department of Energy.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.48)
- Geology > Rock Type > Metamorphic Rock (0.47)
- Geology > Rock Type > Igneous Rock (0.35)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)