Improving Gas-Condensate Recovery Factor and addressing the Flow Assurance Issue with an innovative and highly accurate fluid Sensors for Wet Gas Business

2014 ◽  
Author(s):  
Bruno G. Pinguet
Keyword(s):  
Gas Condensate ◽  
Recovery Factor ◽  
Flow Assurance ◽  
Wet Gas

scholarly journals FLOW ASSURANCE IN KUMUJE WET-GAS PIPELINE: ANALYSIS OF PIGGING SOLUTION TO LIQUID ACCUMULATION

2018 ◽  
Vol 9 (9) ◽  
pp. 380-386
Author(s):  
Sarah Akintola ◽  
Emmanuel Folorunsho ◽  
Oluwakunle Ogunsakin
Keyword(s):  
Pressure Loss ◽  
Gas Pipeline ◽  
Gas Condensate ◽  
Flow Assurance ◽  
Gas Pipelines ◽  
Wet Gas ◽  
Highly Sensitive ◽  
Temperature And Pressure ◽  
Pipeline Corrosion ◽  
Assurance Problem

Liquid condensation in gas-condensate pipelines in a pronounced phenomenon in long transporting lines because of the composition of the gas which is highly sensitive to variations in temperature and pressure along the length of the pipeline. Hence, there is a resultant liquid accumulation in onshore wet-gas pipelines because of the pipeline profile. This accumulation which is a flow assurance problem can result to pressure loss, slugging and accelerated pipeline corrosion if not properly handled.

scholarly journals Effects of the rate of natural gas production on the recovery factor during carbon dioxide injection at the initial gas-water contact

2021 ◽  
Vol 1 (3(57)) ◽  
pp. 6-11
Author(s):  
Serhii Matkivskyi
Keyword(s):  
Carbon Dioxide ◽  
Natural Gas ◽  
Gas Production ◽  
Gas Condensate ◽  
Recovery Factor ◽  
Formation Water ◽  
Hydrocarbon Gases ◽  
Water Contact ◽  
Natural Gas Production ◽  
Gas Recovery

The object of research is gas condensate reservoirs, which is being developed under the conditions of the manifestation of the water drive of development and the negative effect of formation water on the process of natural gas production. The results of the performed theoretical and experimental studies show that a promising direction for increasing hydrocarbon recovery from fields at the final stage of development is the displacement of natural gas to producing wells by injection non-hydrocarbon gases into productive reservoirs. The final gas recovery factor according to the results of laboratory studies in the case of injection of non-hydrocarbon gases into productive reservoirs depends on the type of displacing agent and the level heterogeneity of reservoir. With the purpose update the existing technologies for the development of fields in conditions of the showing of water drive, the technology of injection carbon dioxide into productive reservoirs at the boundary of the gas-water contact was studied using a digital three-dimensional model of a gas condensate deposit. The study was carried out for various values of the rate of natural gas production. The production well rate for calculations is taken at the level of 30, 40, 50, 60, 70, 80 thousand m3/day. Based on the data obtained, it has been established that an increase in the rate of natural gas production has a positive effect on the development of a productive reservoir and leads to an increase in the gas recovery factor. Based on the results of statistical processing of the calculated data, the optimal value of the rate of natural gas production was determined when carbon dioxide is injected into the productive reservoir at the boundary of the gas-water contact is 55.93 thousand m3/day. The final gas recovery factor for the optimal natural gas production rate is 64.99 %. The results of the studies carried out indicate the technological efficiency of injecting carbon dioxide into productive reservoirs at the boundary of the gas-water contact in order to slow down the movement of formation water into productive reservoirs and increase the final gas recovery factor.

The Lomond Field, Block 23/21, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 511-522 ◽  
Author(s):  
Srmuti Jena ◽  
David Olowoleru
Keyword(s):  
Continental Shelf ◽  
North Sea ◽  
Gas Condensate ◽  
Recovery Factor ◽  
High Recovery ◽  
Integrated Production ◽  
Production Platform ◽  
Production Wells ◽  
Production History ◽  
Very High

AbstractLomond is a gas–condensate field on the east flank of the Central Graben UK Continental Shelf, some 230 km east of Aberdeen in Block 23/21. The field was discovered in 1972 and was developed with nine production wells from an integrated production platform. Lomond is a large salt-induced anticline with four-way dip closure. The reservoir comprises Paleocene turbidite sandstones with the majority of the hydrocarbon volume in the Forties Sandstone Member and the top seal is provided by laterally extensive mudstones of the Sele Formation. The field is structurally compartmentalized with three different hydrocarbon–water contacts, but with the gas leg in pressure communication. Significant reservoir and structural complexities are observed in Lomond Field; however, the production behaviour exhibits classical tank-like depletion behaviour over its production history. With a very high recovery factor to date, the field has produced 883 bcf or 86% of the gas resource initially in place.

Advantages of lean gas for an upstream gas-gathering system

2011 ◽  
Vol 51 (2) ◽  
pp. 735
Author(s):  
Dave Hazle
Keyword(s):  
Flow Assurance ◽  
Wet Gas ◽  
Technology Applications

Offshore lean gas developments are often perceived as being inferior to a wet gas development. In this case study, the advantages of lean gas are shown to be an enabler, making a project viable in an area where many small lean gas accumulations combine to produce a viable development. Through beneficial flow assurance, cheaper and simpler facilities, larger drainage radii and technology applications such as DEH, viability of a development can be demonstrated in an area where smaller discoveries are currently perceived as being stranded.

Unlocking Surface Constraints for High Temperature Gas Field: Production Network Compositional Variation Analysis for Wet Gas Meter PVT Calibration Approach

2021 ◽  
Author(s):  
Shaturrvetan Karpaya ◽  
Sulaiman Sidek ◽  
Dani Angga Ab Ghani ◽  
Hazrina Ab Rahman ◽  
Aivin Yong ◽  
...  
Keyword(s):  
High Temperature ◽  
Gas Condensate ◽  
Production Network ◽  
Total Field ◽  
Production Rates ◽  
Gas Field ◽  
Wet Gas ◽  
Tracer Dilution ◽  
Gas Ratio ◽  
Field Production

Abstract Installation of Wet Gas Metering System (WGMS) on a platform for the purposes of real-time measurement of liquid and gas production rates as well as performance monitoring as part of reservoir and production optimization management are quite common nowadays in Malaysia. Nonetheless, understanding of wells production deliverability invariably measured using these Wet Gas Meter (WGM) which provides the notion of production rates contributed by the wells are paramount important, eventually the produced fluids will be processed by various surface equipment at the central processing platform before being transport to onshore facilities. However, the traditional WGM are known to operate within ±10% accuracy, whereby the confidence level on measurement of the produced fluids can be improved either by updating with accurate PVT flash table or combination of results from performing tracer dilution technique for data verification. Sarawak Gas Field contains a number of gas fields offshore East Malaysia, predominantly are carbonate type formation, where one (1) of the field operated by PETRONAS Carigali Sdn.Bhd.(PCSB) is a high temperature accumulation at which temperature at the Gas Water Contact (GWC) approximately 185°C and full wellstream Flowing Tubing Head Temperature (FTHT) records at 157°C. Cumulative field production of five (5) wells readings from WGM had shown 9.1% differences as compared to the export meter gas readings. As part of a strategy to provide maximum operational flexibility, improvement on accuracy of the WGM is required given that the wells have higher Technical Potential (TP) but are limited by threshold of the multi-stage surface processing capacity. This also impacts commerciality of the field to regaining the cost of capital investment and generate additional revenue especially when there is a surge in network gas demand, as the field unable to swiftly ramp-up its production to fulfill higher gas demand considering the reported production figures from cumulative WGM surpassing the surface equipment Safe Operating Envelope (SOE). Our approach begins with mass balance check at the WGMS and export meter including the fuel, flare and Produced Water Discharge (PWD) to check mass conservation by phases because regardless different type of phases change occurs at topside the total mass should be conserved (i.e. for total phases of gas, condensate and water) provided that precise measurement by the metering equipment. Tracer dilution measurement of gas, condensate and water flowrates were used to verify the latest calibrated Water Gas Ratio (WGR) and Condensate Gas Ratio (CGR) readings input into the WGM. Consequently, PVT separator samples were also taken via mini-separator for compositional analysis (both gas and condensate) and for mathematical recombination at the multi-rates CGR readings to generate a representative PVT compositional table. Simultaneously, process model simulation run was conducted using full wellstream PVT input to validate total field production at the export point. This paper presents practical approach to balance the account, to ensure the SOE at topside as well as to improve the PVT composition at the WGM for high temperature field that emphasizes on understanding of compositional variations across production network causing significant differences in total field production between WGM and the allocation meter.

Leading Edge Flow Assurance Management Strategy to Optimize the Design and Operations, for a Deepwater Gas Condensate Reservoir, Reducing Costs and Associated Risks Through Integrated Engineering Analysis

2021 ◽  
Author(s):  
Julio Cesar Villanueva Alonso ◽  
Oswaldo Espinola Gonzalez ◽  
Julieta Alvarez Martinez
Keyword(s):  
Deep Water ◽  
Potential Flow ◽  
Management Strategy ◽  
Management Practices ◽  
Leading Edge ◽  
Reservoir Management ◽  
Gas Condensate ◽  
Mitigation Strategies ◽  
Flow Assurance ◽  
Reducing Costs

Abstract Most operator companies work under a philosophy of responding with mitigation strategies rather than prevention ones to flow assurance problems when they arise. Although mitigation strategies help to maintain a stable production, gas condensate fields require the implementation of proactive techniques to be prepared for future scenarios, especially when it comes to deep water environments, since the combination of the changes in composition of a condensate fluid and the thermodynamic considerations of producing in deep water fields increase the frequency of operational problems and therefore, additional costs and risks. Furthermore, the concept of management is not frequently applied to the Flow Assurance area as much as the concept of Reservoir Management. Analogous to best Reservoir Management practices, this concept can be translated to the design and operation in the flow assurance area to provide more robust and precise analysis. Taking these considerations into account, a proactive approach is required, so that operator companies can better prepare and act in an optimum way. This paper presents a Flow Assurance Management Strategy (FAMS) methodology focused on increasing and improving the response capacity through understanding the behavior of production trends, predicting the come up of potential flow assurance problems. By the implementation of this methodology, we are seeking to operators obtain a full perspective of all the potential problems that will eventually can take place in their fields, identifying, when, where and why they will occur, and thus, allowing to set proactive actions to minimize unexpected potential flow assurance problems. The objective of this paper is to share a detailed methodology, which is intended to apply for any kind of flow assurance problem, helping operators to implement the best solution according to their capabilities and to set a base to homologate the concept of management, additionally, a short case in which an optimization study was carried out is shown for demonstration purposes.

Results from First Campaign of Field Testing of Multiphase Flow Meters Conducted in Saudi Arabian Wet Gas-Condensate Producers.

2013 ◽  
Author(s):  
Ruben Villegas Rodriguez ◽  
Jairo A. Leal ◽  
Shahid Hussain ◽  
Mohammed Atwi ◽  
Azmi Ruwaished ◽  
...  
Keyword(s):  
Multiphase Flow ◽  
Saudi Arabian ◽  
Field Testing ◽  
Gas Condensate ◽  
Flow Meters ◽  
Wet Gas
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