A Study on Hydrate Inhibition of Marginal Gas Field Development

2020 ◽  
Author(s):  
Hualei Yi
Keyword(s):  
Double Layer ◽  
Hydrate Formation ◽  
Economic Benefits ◽  
Development Project ◽  
Gas Production ◽  
Gas Field ◽  
Subsea Pipeline ◽  
Field Development ◽  
Development Engineering ◽  
First Time

Abstract In the marginal gas field development engineering, considering the low gas production with complex reservoir condition, it is difficult to develop independently because of the low economic efficiency. It is usually developed by relying on an existing offshore platform or facility nearby, in which hydrate inhibition is an important issue, and in order to inhibit hydrate formation in the subsea pipeline, hydrate inhibition method should be studied. Based on certain marginal gas field development project in South China Sea, which relies on nearby DPP platform, the paper studies methanol and MEG as inhibitor and application of double-layer insulated subsea pipeline. Finally by technical and economic comparisons, for the first time double-layer insulated pipeline is selected as the hydrate inhibition method to meet requirements of both relying on DPP and achieving better economic benefits, which is expected to provide reference for similar marginal gas field development.

scholarly journals Research on Gas-liquid Mixed Transportation Technological Adaptability: A Case Study of the Western Sichuan Gas Field

2017 ◽  
Vol 10 (1) ◽  
pp. 37-47
Author(s):  
Qingsha Zhou ◽  
Kun Huang ◽  
Yongchun Zhou
Keyword(s):  
Flow Simulation ◽  
Field Tests ◽  
Economic Benefits ◽  
Gas Production ◽  
Simulation Software ◽  
Rapid Decline ◽  
Gas Field ◽  
Western Sichuan ◽  
Field Development ◽  
Well Production

Background: The western Sichuan gas field belongs to the low-permeability, tight gas reservoirs, which are characterized by rapid decline in initial production of single-well production, short periods of stable production, and long periods of late-stage, low-pressure, low-yield production. Objective: It is necessary to continue pursuing the optimization of transportation processes. Method: This paper describes research on mixed transportation based on simplified measurements with liquid-based technology and the simulation of multiphase processes using the PIPEPHASE multiphase flow simulation software to determine boundary values for the liquid carrying process. Conclusion: The simulation produced several different recommendations for the production and maximum multiphase distance along with difference in elevation. Field tests were then conducted to determine the suitability of mixed transportation in western Sichuan, so as to ensure smooth progress with fluid metering, optimize the gathering process in order to achieve stable and efficient gas production, and improve the economic benefits of gas field development.

Digital Enablement Through Effective Deployment and Commissioning of Instrumentation, Supervisory Control and Data Acquisition System SCADA in Surface Facilities

2021 ◽  
Author(s):  
Gaojing Cao ◽  
Xiangzeng Wang ◽  
Lei Nie ◽  
Yaoqiang Hu ◽  
Yundong Xie ◽  
...  
Keyword(s):  
Big Data ◽  
Data Science ◽  
Oil And Gas ◽  
Data Gathering ◽  
Development Project ◽  
Gas Production ◽  
Acceptance Test ◽  
Gas Field ◽  
Field Development ◽  
Scada Systems

Abstract In the era of all-encompassing Big Data and the Internet of Things (IoT), mastery of Instrument Control (I&C) and SCADA systems deployment is becoming more important as the Operational Technology (OT) foundation for digital integration, data gathering, processing, analytics, and the optimization of business results. Integration and communication between different I&C and SCADA products and systems in an Oil and Gas project represent a significant challenge. The issues encountered on projects globally can prolong project schedules from weeks to months with consequential impacts on commercial gas production, project cash flow, and economics. This paper presents how to enable digital operations through holistic design, well-organized kickoff, effective Integrated Factory Acceptance Test (IFAT), and timely commissioning of I&C and SCADA systems for surface facilities of a gas field development project. It provides a feasible, economical and proven solution to address the foregoing challenges. Furthermore, in this paper we present a snapshot of how to use the latest data-science technology to bring out the value of the gold mine - big data generated by the I&C and SCADA systems.

The Importance of Elemental Sulphur, Mercury and Condensate Identification in Sour Gas Field Development Project: Case Study

2014 ◽  
Author(s):  
Ardian Nengkoda ◽  
Mofeed Awwami ◽  
Xiaolong Cai ◽  
Jamal Mufleh ◽  
Bader Harbi ◽  
...  
Keyword(s):  
Development Project ◽  
Elemental Sulphur ◽  
Gas Field ◽  
Field Development ◽  
Sour Gas

DEEPWATER GAS FIELD PRODUCTION FROM SUBSEA WELLS INTO COMPRESSED NATURAL GAS CARRIERS THROUGH A HYBRID RISER TOWER

2005 ◽  
Vol 45 (1) ◽  
pp. 45
Author(s):  
J-F. Saint-Marcoux ◽  
C. White ◽  
G.O. Hovde
Keyword(s):  
Natural Gas ◽  
Eddy Currents ◽  
Gas Production ◽  
Lessons Learned ◽  
Concept Design ◽  
Vertical Load ◽  
Gas Field ◽  
Compressed Natural Gas ◽  
Field Development ◽  
Field Production

This paper addresses the feasibility of developing an ultra-deepwater gas field by producing directly from subsea wells into Compressed Natural Gas (CNG) Carrier ships. Production interruptions will be avoided as two Gas Production Storage Shuttle (GPSS) vessels storing CNG switch out roles between producing/storing via one of two Submerged Turret Production (STP) buoys and transport CNG to a remote offloading buoy. This paper considers the challenges associated with a CNG solution for an ultra-deepwater field development and the specific issues related to the risers. A Hybrid Riser Tower (HRT) concept design incorporating the lessons learned from the Girassol experience allows minimisation of the vertical load on the STP buoys. The production switchover system from one GPSS to the other is located at the top of the HRT. High-pressure flexible flowlines with buoyancy connect the flow path at the top of HRT to both STP buoys. System fabrication and installation issues, as well as specific met ocean conditions of the GOM, such as eddy currents, have been addressed. The HRT concept can be also used for tiebacks to floating LNG plants.

JOHN BROOKES GAS FIELD DEVELOPMENT

2005 ◽  
Vol 45 (1) ◽  
pp. 13
Author(s):  
A.J. McDiarmid ◽  
P.T. Bingaman ◽  
S.T. Bingham ◽  
B. Kirk-Burnnand ◽  
D.P. Gilbert ◽  
...  
Keyword(s):  
Low Cost ◽  
Time Frame ◽  
Gas Production ◽  
Gas Field ◽  
Initial Development ◽  
North West ◽  
Field Development ◽  
The North ◽  
Production Wells ◽  
Development Approach

The John Brookes gas field was discovered by the drilling of John Brookes–1 in October 1998 and appraisal drilling was completed in 2003. The field is located about 40 km northwest of Barrow Island on the North West Shelf, offshore West Australia. The John Brookes structure is a large (>90 km2) anticline with >100 m closure mapped at the base of the regional seal. Recoverable sales gas in the John Brookes reservoir is about 1 Tcf.Joint venture approval to fast track the development was gained in January 2004 with a target of first gas production in June 2005. The short development time frame required parallel workflows and use of a flexible/low cost development approach proven by Apache in the area.The John Brookes development is sized for off-take rates up to 240 TJ/d of sales gas with the development costing A$229 million. The initial development will consist of three production wells tied into an unmanned, minimal facility wellhead platform. The platform will be connected to the existing East Spar gas processing facilities on Varanus Island by an 18-inch multi-phase trunkline. Increasing the output of the existing East Spar facility and installation of a new gas sweetening facility are required. From Varanus Island, the gas will be exported to the mainland by existing sales gas pipelines. Condensate will be exported from Varanus Island by tanker.

Economic Risk Analysis of Offshore Projects

1992 ◽  
Vol 114 (3) ◽  
pp. 165-174 ◽  
Author(s):  
E. M. Bitner-Gregersen ◽  
J. Lereim ◽  
I. Monnier ◽  
R. Skjong
Keyword(s):  
Net Present Value ◽  
Oil And Gas ◽  
Development Project ◽  
Oil Field ◽  
Economic Risk ◽  
Gas Field ◽  
Cost Overruns ◽  
Field Development ◽  
Project Assessment ◽  
Oil Field Development

A quantitative analysis of economic risk associated with large investments in offshore oil and gas field development and production is presented. The analysis is intended as a supporting tool in decision-making faced with uncertainty and risk, to study the effect of alternative decisions in an easy manner. The descriptors for the project assessment, such as the Internal Rate of Return (IRR) and Net Present Value (NPV) are applied. The study demonstrates first the impacts of early pilot production (EPP) prior to a main oil field development on the field economy of an oil field development and production installation. Furthermore, the result of cases which reflect relevant situations connected with cost overruns are presented, as well as derivation of rational decision criteria for termination/continuation of a project subjected to cost overruns. Finally, an oil field development project scheduling is demonstrated.

A Study of Hydrate Inhibition for Deepwater Gas Field Development

2019 ◽  
Author(s):  
Hualei Yi ◽  
Yun Hao ◽  
Xiaohong Zhou
Keyword(s):  
Produced Water ◽  
Water Flow Rate ◽  
Injection Rate ◽  
Gas Field ◽  
Subsea Pipeline ◽  
Field Development ◽  
Flow Simulations ◽  
The World ◽  
Gas Fields ◽  
Selection Of

Abstract For deepwater subsea tie-back gas field development, hydrate tends to be formed in deepwater subsea production system and gas pipeline due to high pressure and low temperature. Based on the gas field A development, this paper studies the selection of hydrate inhibitors and injection points, i.e. different injection points with different inhibitors. Transient and steady flow simulations are performed using the OLGA software widely used for multiphase flow pipeline study in the world. The produced water flow rate affects the hydrate inhibition in case of well opening, including cases of different times with different water temperatures. This paper presents the calculation of the maximum inhibitor injection rate in the subsea pipeline by taking the whole production years into consideration. The measures on hydrate remediation are taken by quickly relieving the subsea pipeline pressure from wellheads and the platform according to different hydrate locations. Now more and more deepwater gas fields are developed in South China Sea and around the world. The experience obtained from the gas field A development will benefit the hydrate inhibition for future deepwater gas field development.

scholarly journals Evaluation of Oil and Gas Economy using Economics Profit Indicators and Prototype Macro VBA Excel

2021 ◽  
Vol 1 (1) ◽  
pp. 549-558
Author(s):  
Juwairiah Juwairiah ◽  
Didik Indarwanta ◽  
Frans Richard Kodong
Keyword(s):  
Economic Analysis ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Development Project ◽  
Economic Indicators ◽  
Gas Field ◽  
Gas Industry ◽  
Field Development ◽  
Oil And Gas Field ◽  
Oil And Gas Sector

The oil and gas sector is an important factor in sustainable development, so it is considered necessary to make serious changes in conducting economic analysis on the oil and gas business. Oil and gas industry activities consist of upstream activities, and downstream activities. Activities in these upstream and downstream operations have high risk, high costs and high technology, so the company continuously tries to reduce the importance of the adverse impact of these risks on the work environment and people. Thus, evaluating the factors that affect sustainable production in this sector becomes a necessity. In this research will be evaluated the economy of the oil and gas field using methods of economic indicators, among others; NPV, POT, ROR, where these factors are estimated in order to be able to estimate the prospects of the oil and gas field so that the decision that the field development project can be implemented or cannot be taken immediately. Implementation of oil and gas field economic evaluation in this study using Macro VBA Excel. From several methods of economic analysis obtained that the results of this study show high precision compared to other methods, in addition to the way of evaluation using the above economic indicators is very popular.

scholarly journals An Approach to Estimation of Gas Reserve of Narshingdi Gas Field in Bangladesh with Dynamic Reservoir Simulation

2017 ◽  
Vol 29 (1) ◽  
pp. 19-23
Author(s):  
Farhana Akter
Keyword(s):  
Reservoir Simulation ◽  
Chemical Engineering ◽  
National Level ◽  
Development Stage ◽  
Gas Production ◽  
Rock Properties ◽  
Reserve Estimation ◽  
Gas Field ◽  
Field Development ◽  
Increasing Demand

Increasing demand of fuel globally formulates gas as one of the most valuable natural resources. There is lot of uncertainties in estimating hydrocarbon volume correctly from exploration to development stage of a gas field. The accuracy and reliability of data (reservoir geological model, fluid and rock properties) make the implement very hard-hitting. So estimating and updating the gas reserve has become vital issue, as it helps the planners for drawing mid-term and long-term development plan from field development level to national level. This paper presents the study of reserve estimation of a Narshingdi Gas Field in Bangladesh. In this paper, a dynamic reservoir simulation model has been used to perform a history match ?pressure and production? using commercial simulator for reserve estimation. The result of this study is expected to provide Gas Initially in Place (GIIP) and recoverable gas volume. Simultaneously three forecast scenarios have also been investigated. There is no strong aquifer pressure support in the producing gas zone, so gas production continues from the reservoir due to pressure depletion.Journal of Chemical Engineering, Vol. 29, No. 1, 2017: 19-23

Remote-Controlled Automated Foam Injection: A Digital Solution to Liquid Loading in a China Unconventional Gas Development

2021 ◽  
Author(s):  
Jiang Wei Bo ◽  
Beryl Audrey ◽  
Uzezi Orivri ◽  
Nian Xi Wang ◽  
Xiang Yang Qiao ◽  
...  
Keyword(s):  
Remote Control ◽  
Continuous Production ◽  
Weather Conditions ◽  
Gas Production ◽  
Liquid Loading ◽  
Gas Field ◽  
Field Development ◽  
Operational Risks ◽  
Tight Gas Reservoir ◽  
Unconventional Gas Development

Abstract Gas field C is an unconventional tight gas reservoir located in the central of China which has prominent characteristics, including thin formation, low permeability and poor reservoir connectivity which significantly impact on the field development. Horizontal wells multistage hydraulic fracturing has been proven to be an effective technique to recover the hydrocarbons from this gas field. However, with continuous production overtime, reservoir pressure declines which results in a decrease in gas production rate below the critical gas velocity, leading to accumulation of liquid in the wellbore (liquid loading), which further results in back pressure and damage to the formation. Currently, gas field C loses up to 1500 mmscf/year in gas production and associated revenue due to liquid loading. Some other factors which hinders effective deliquification of the gas wells include remote well pad locations, poor road conditions during harsh weather conditions, friction with local communities, limited manpower to daily effectively analyze over 200 wells for liquid loading diagnostics and operational risks during well intervention. To tackle these challenges, a new versatile intelligent dosing technology has been piloted to reduce liquid loading. This remote-control dosing unit is located at the well pad and is equipped with automatic valves that can dispense two different chemicals (soap and methanol) in one unit. A key new feature of this system is the ability to receive and implement instructions that optimizes the dosing rate and frequency. This remote-control functionality eliminates on-site operator intervention and HSE risks especially in winter when the well pads could be inaccessible with poor road conditions.

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