Integrated Production Modelling of Gas Condensate Field

2014 ◽  
Author(s):  
Mayembe Joao Bartolomeu ◽  
Adkar Bulatovich Abdrakhmanov
Keyword(s):  
Gas Condensate ◽  
Integrated Production ◽  
Production Modelling

An Integrated Production Modelling workflow for CSG production forecasting and optimisation

2016 ◽  
Vol 34 ◽  
pp. 733-750
Author(s):  
A. Shields ◽  
S. Tihonova ◽  
R. Stott ◽  
L.A. Saputelli ◽  
Z. Haris ◽  
...  
Keyword(s):  
Integrated Production ◽  
Production Forecasting ◽  
Production Modelling

Lessons Learnt from Integrated Production Modelling and Performance Analysis of Gas Lift Wells of One of the Biggest Offshore Complexes in India

2021 ◽  
Author(s):  
Sagun Devshali ◽  
Ravi Raman ◽  
Sanjay Kumar Malhotra ◽  
Mahendra Prasad Yadav ◽  
Rishabh Uniyal
Keyword(s):  
Performance Analysis ◽  
Flow Line ◽  
Gas Injection ◽  
Injection Rate ◽  
Oil Wells ◽  
Nodal Analysis ◽  
Integrated Production ◽  
And Performance ◽  
Gas Lift ◽  
Production Modelling

Abstract The paper aims to discuss various issues pertaining to gas lift system and instabilities in low producer wells along with the necessary measures for addressing those issues. The effect of various parameters such as tubing size, gas injection rate, multi-porting and gas lift valve port diameter on the performance analysis of integrated gas lift system along with the flow stability have been discussed in the paper. Field X is one of the matured offshore fields in India which has been producing for over 40 years. It is a multi-pay, heterogeneous and complex reservoir. The field is producing through six Process Complexes and more than 90% of the wells are operating on gas lift. As most of the producing wells in the field are operating on gas lift, continuous performance analysis of gas lift to optimize production is imperative to enhance or sustain production. 121 Oil wells and 7 Gas wells are producing through 18 Wellhead platforms to complex X1 of the field X. Out of these 121 oil wells, 5 are producing on self and remaining 116 with gas lift. In this paper, performance analysis of these 116 flowing gas lift wells, carried out to identify various problems which leads to sub-optimal production such as inadequate gas injection, multi-porting, CV choking, faulty GLVs etc. has been discussed. On the basis of simulation studies and analysis of findings, requisite optimization/ intervention measures proposed to improve performance of the wells have been brought out in the paper. The recommended measures predicted the liquid gain of about 1570 barrels per day (518 barrels of oil per day) and an injection gas savings in the region of about 28 million SCFD. Further, the nodal analysis carried out indicates that the aforementioned gas injection saving of 28 million SCFD would facilitate in minimizing the back pressure in the flow line network and is likely to result in an additional production gain of 350 barrels of liquid per day (65 barrels of oil per day) which adds up to a total gain of 1920 barrels of liquid per day (583 barrels of oil per day). Additionally, system/ nodal analysis has also been carried out for optimal gas allocation in the field through Integrated Production Modelling. The analysis brings out a reduction in gas injection by 46 million SCFD with likely incremental oil gain of ~100 barrels of oil per day.

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.

The use of integrated production modelling to assess network efficiency and production system optimisation

2019 ◽  
Vol 59 (1) ◽  
pp. 211
Author(s):  
Y. Fei ◽  
G. Lydyard ◽  
A. Mantopoulos ◽  
D. Marques ◽  
M. Rondon
Keyword(s):  
Production System ◽  
Production Network ◽  
Network Efficiency ◽  
Screening Process ◽  
Water Separation ◽  
Petroleum Production ◽  
Integrated Production ◽  
Special Cases ◽  
System Optimisation ◽  
Production Modelling

This paper investigates the use of integrated production models to apply a consistent and repeatable approach to assess petroleum production network efficiency and aid production system optimisation. Assessing network efficiency in the manner detailed in this paper allows petroleum professionals to define a maximum network production through the analysis of the pressure drop within a network. This is achieved by comparing the system base production to a simulation of theoretical wellhead water separation (for all inflows), larger diameters of all surface pipelines (double the diameter is used as a maximum case) and a combination of the two using integrated production modelling (IPM). The combination of water separation and larger diameter of all the pipelines represented the maximum network production possible for tangible projects. This allowed the definition of network efficiency value of a petroleum production system on a scale of 0% to 100%. At a screening level, the lower the Network Efficiency Metric (NEM) the greater the likelihood of an optimisation opportunity, prompting additional assessment of special cases. This method was applied to a network of 40 wells using IPM, and NEM values of 95.9% (water separation), 94.6% (double pipeline diameter) and 83.5% (combined) were obtained. These values of network efficiency also corresponded to incremental reserve difference of 4.3, 5.8 and 20.1 Bscf, respectively. The NEM was a crucial component of the screening process and demonstrated an alternative and efficient method for the identification of optimisation projects, which increased production and reserves.

Integrated production modelling of the Wheatstone-Iago fields: boon or bane?

2012 ◽  
Vol 52 (2) ◽  
pp. 639
Author(s):  
Gbenga Afuape ◽  
Myles Regan ◽  
Ronald May ◽  
Vernon Roewer ◽  
Anton Chung ◽  
...  
Keyword(s):  
Large Scale ◽  
Oil And Gas ◽  
Simulation Models ◽  
Oil And Gas Industry ◽  
Pipeline System ◽  
Gas Industry ◽  
Full Field ◽  
Integrated Production ◽  
Surface Network ◽  
Production Modelling

Applying integrated production modelling (IPM) for decision making in the oil and gas industry has proliferated rapidly, evidenced by the amount of published information about successful applications of this approach. A reason for its popularity is to mitigate the risk of over(under)investment, which is driving asset teams toward jettisoning the practice of using fixed THP to account for backpressure effects or to use the limited surface network options available in most numerical reservoir simulators. This extended abstract describes the modelling of an offshore gas development by coupling multiple full-field, numerical reservoir simulation models with a shared surface network model. Such an approach enabled subsurface elements of the production system to be linked directly to surface elements (subsea and platform) yielding a fully coupled IPM. Key development decisions were tested and justified in a technically rigorous and economically robust manner. These decisions included the phasing of development wells, compression requirements and flow balancing in the pipeline system to maintain specified gas delivery rates. Experience from this approach has shown traditional reservoir engineering techniques can still yield the same outcome as an IPM with comparable accuracy—for some development decisions such as using a creaming curve and fixed THP to determine optimum well count; nevertheless, using simple methods to account for backpressure effects may not allow the same broad-based integration of design requirements needed at the design and engineering stage of large-scale projects. The PowerPoint presentation is not available to APPEA.

Integrated Production Modelling for CSG Production Forecasting

2015 ◽  
Author(s):  
A. Shields ◽  
S. Tihonova ◽  
R. Stott ◽  
L. A Saputelli ◽  
Z. Haris ◽  
...  
Keyword(s):  
Integrated Production ◽  
Production Forecasting ◽  
Production Modelling
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