scholarly journals Comparative study for connecting new flare capacity to existing flare Systems

2021 ◽  
Vol 58 (1) ◽  
pp. 5795-5808
Author(s):  
Mohamed Shamandy Fouad Et al.
Keyword(s):  
Comparative Study ◽  
Production Rate ◽  
Oil And Gas ◽  
Production Capacity ◽  
System Capacity ◽  
Remote Point ◽  
Petroleum Company ◽  
Gas Plants

Process facility operations are equipped with flare system to dispose flammable, toxic, or corrosive vapors to an environmentally acceptable gas for release to the atmosphere from both normal operational venting and relief during abnormal conditions. For safe incineration and radiation considerations flares are located at a remote point from the plant. Flare system when designed is to be limited for a certain capacity for a relieved gas; in addition, it may be designed in excess for future process facilities which may be further added to an existing one. KHALDA Petroleum Company is an owner company of oil and gas plants in Egypt. The company started a remote facility in 2005 named as "QASR start of line" which equipped with a limited flaring system capacity of 416,800 kg/hr for each flare related to phases PH-1 and PH-2. After 10 years of operation the wells depletion occurred which affected the production capacity and hence the company decided to maintain the productivity. A new compression project is designed to improve recovery as the reservoir production rate and pressure decline. The new compression project facilities vent and disposal need a flare system in case of the emergency. This paper discusses two different scenarios available for connecting the new compression project facilities vent and disposal system either to the existing flare systems or to another destination, which better, safer and more economic  

Development and Execution of Heritage Petroleum Company Limited’s First Offshore Workover Campaign - A Case History of Successful Implementation of Performance Management

2021 ◽  
Author(s):  
Shazim Mohammed ◽  
Dale Persad ◽  
Kirk Baksh
Keyword(s):  
Trinidad And Tobago ◽  
Performance Management ◽  
Net Present Value ◽  
Oil And Gas ◽  
Selection Process ◽  
Public Procurement ◽  
Dynamic Modelling ◽  
Successful Implementation ◽  
Procurement Process ◽  
Petroleum Company

Abstract Heritage Petroleum Company Limited (HPCL) is the newest operating oil and gas company in Trinidad and Tobago and was vested and entrusted with the operation and management of all the exploration and production assets of Petroleum Company of Trinidad and Tobago Limited ("Petrotrin"). Being driven by oil-based revenue meant that rig intervention projects had to be innovative, economically viable and practical to meet the company’s financial commitments. This paper presents the concepts and processes behind the development and implementation of HPCL’s Workover Scoping and Procurement Framework. The offshore team recognized the need to frame the well review and workover candidate selection process as well as a procurement process that was both operationally accommodating and in accordance with public procurement regulations. This process would also have to be tested, since it was a new concept that was not practiced by Petrotrin. The well review process involved defining reservoir deliverability and in-place volumes through static and dynamic modelling, establishing current well potential and deliverability via nodal analysis with installed completion designs, topside infrastructure conditions and flow restrictions. The procurement process was achieved by identifying local resources and generating framework agreements for services and equipment. Job specific resources were tendered to ensure a transparent selection and award. The process also involved ranking the risks of all candidates. Economic analyses were performed to determine whether the financial indicators were positive to ensure viability of the campaign. A scorpion plot was also used to manage the performance of this framework during the campaign. The result was a campaign consisting of 15 wells that was delivered on time and within the workover budget. Actual production gain was over 1700 BOPD as opposed to the expected gain of 1450 BOPD. Budgeted Net Present Value (NPV) and actual NPV was calculated to be US$ 9.42 million dollars and US$ 11.7 million dollars respectively. All resources were demobilized and removed from the offshore acreage to reduce risks and floating expense to the company at the end of the campaign.

A Framework to Support the Optimization of Modularized Oil and Gas Structures

2018 ◽  
Author(s):  
Vincenzo Castorani ◽  
Paolo Cicconi ◽  
Michele Germani ◽  
Sergio Bondi ◽  
Maria Grazia Marronaro ◽  
...  
Keyword(s):  
Lead Time ◽  
Oil And Gas ◽  
Steel Structure ◽  
Steel Structures ◽  
Modular System ◽  
Test Case ◽  
Plant Design ◽  
Conceptual Study ◽  
A Current ◽  
Gas Plants

Modularization is a current issue in the context of plant design. A modular system aims to reduce lead time and cost in design phases. An oil & gas plant consists of many Engineered-To-Order solutions to be submitted and approved during the negotiation phase. In this context, design tools and methods are necessary to support the design life cycle from the conceptual study to the detailed project. The paper proposes an approach to optimize the design of modularized oil & gas plants with a focus on the related steel structures. A test case shows the configuration workflow applied to a modular steel structure of about 400 tons. The modularized layout has been optimized using genetic algorithms. A Knowledge Base has been described to support the configuration phase related to the conceptual design. Design rules and metrics have been formalized from the analysis of past solutions.

Prediction of Sand Production Through Porous Media: Mechanisms and Challenges to Optimising the Inefficiencies

2021 ◽  
Vol 18 (4) ◽  
pp. 45-52
Author(s):  
Wenhua Huang ◽  
Yan Huang ◽  
Juan Ren ◽  
Jinglong Jiang ◽  
Marischa Elveny
Keyword(s):  
Production Rate ◽  
Oil And Gas ◽  
Phenol Formaldehyde ◽  
Fundamental Issue ◽  
Sand Production ◽  
Drag Forces ◽  
Induced Drag ◽  
Porosity And Permeability ◽  
Production Conditions ◽  
Methods Of Control

One of the challenges facing drilling companies in the completion and production of oil and gas wells is sand production from the formation. The ability to predict sand production in the wells of a reservoir, to decide to use different methods of control is considered a fundamental issue. Therefore, analysis and study of sand production conditions and selecting the optimal drilling route before drilling wells are significant issues that are less considered. According to the findings of this study, due to the sand grains adhesion issue, saturation increase has caused to increase in the intermolecular uptake, and therefore moisture has been decreased. It leads to reduction in the sand production rate. Pressure increase has a direct relationship with the sand production rate due to increased induced drag forces. Moreover, phenol–formaldehyde resins provided an acceptable measurement as there are no significant changes in porosity and permeability.

Application of raypath modelling to verify the mapping of Gippsland gas fields

1989 ◽  
Vol 20 (2) ◽  
pp. 325
Author(s):  
M. Megallaa
Keyword(s):  
Oil And Gas ◽  
Synthetic Data ◽  
Production Capacity ◽  
Normal Incidence ◽  
Wave Theory ◽  
Seismic Profiles ◽  
Well Control ◽  
Depth Maps ◽  
Petroleum Resources ◽  
Gas Fields

One of the Victorian Government's policies in the oil and gas area is to enhance the benefits to the State in the energy sector by assessing the nature and extent of the petroleum resources. To evaluate the production capacity of developed and undeveloped gas fields, a comprehensive study was commissioned by the DITR in 1988. The first step in a study of this type is to check the accuracy of the depth maps, to see if they adequately describe the reservoir geometry. Raypath modelling, using the Advanced Interpretation Mapping System (AIMS ? Version III), was carried out by Geophysical Services International (GSI), Sydney, on a number of selected profiles over the Snapper, Marlin-Turrum, Barracouta, Kipper and Emperor fields for the DITR. Input data for the models were extracted from the operator's maps. The software simulates the normal incidence raypaths (or wave theory solution) for all shotpoints, and from this information it generates gather records and/or synthetic seismic profiles. By comparing the model data with those from data acquisition, processing and interpretation, it was possible to check the validity of the interpretation of the reservoir's geometry. This modelling work showed that the synthetic data were comparable with the acquisition and processing data, confirming that the depth maps (tied to well control) produced by the operator using its proprietary software are adequate and most likely to represent subsurface configuration of the reservoirs.

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