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.

Chemical Deliquification of Unconventional Gas Wells

2014 ◽  
Author(s):  
K.. Francis-LaCroix ◽  
D.. Seetaram
Keyword(s):  
Natural Gas ◽  
Best Practice ◽  
Oil And Gas ◽  
Large Deviation ◽  
Cost Effective ◽  
Gas Production ◽  
Lessons Learned ◽  
Offshore Platforms ◽  
Gas Wells ◽  
Current Production

Abstract Trinidad and Tobago offshore platforms have been producing oil and natural gas for over a century. Current production of over 1500 Bcf of natural gas per year (Administration, 2013) is due to extensive reserves in oil and gas. More than eighteen of these wells are high-producing wells, producing in excess of 150 MMcf per day. Due to their large production rates, these wells utilize unconventionally large tubulars 5- and 7-in. Furthermore, as is inherent with producing gas, there are many challenges with the production. One major challenge occurs when wells become liquid loaded. As gas wells age, they produce more liquids, namely brine and condensate. Depending on flow conditions, the produced liquids can accumulate and induce a hydrostatic head pressure that is too high to be overcome by the flowing gas rates. Applying surfactants that generate foam can facilitate the unloading of these wells and restore gas production. Although the foaming process is very cost effective, its application to high-producing gas wells in Trinidad has always been problematic for the following reasons: Some of these producers are horizontal wells, or wells with large deviation angles.They were completed without pre-installed capillary strings.They are completed with large tubing diameters (5.75 in., 7 in.). Recognizing that the above three factors posed challenges to successful foam applications, major emphasis and research was directed toward this endeavor to realize the buried revenue, i.e., the recovery of the well's potential to produce natural gas. This research can also lead to the application of learnings from the first success to develop treatment for additional wells, which translates to a revenue boost to the client and the Trinidad economy. Successful treatments can also be used as correlations to establish an industry best practice for the treatment of similarly completed wells. This paper will highlight the successes realized from the treatment of three wells. It will also highlight the anomalies encountered during the treatment process, as well as the lessons learned from this treatment.

Optimization Applied to Buzios Flexible Riser Systems and Subsea Layout

2021 ◽  
Author(s):  
Vinicius Gasparetto ◽  
Thierry Hernalsteens ◽  
Joao Francisco Fleck Heck Britto ◽  
Joab Flavio Araujo Leao ◽  
Thiago Duarte Fonseca Dos Santos ◽  
...  
Keyword(s):  
Deep Water ◽  
Technology Use ◽  
Capital Expenditure ◽  
Lessons Learned ◽  
Internal Diameter ◽  
Flexible Riser ◽  
Flexible Pipe ◽  
Injection Wells ◽  
Gas Field ◽  
Field Development

Abstract Buzios is a super-giant ultra-deep-water pre-salt oil and gas field located in the Santos Basin off Brazil's Southeastern coast. There are four production systems already installed in the field. Designed to use flexible pipes to tie back the production and injection wells to the FPSOs (Floating Production Storage and Offloading), these systems have taken advantage from several lessons learned in the previous projects installed by Petrobras in Santos Basin pre-salt areas since 2010. This knowledge, combined with advances in flexible pipe technology, use of long-term contracts and early engagement with suppliers, made it possible to optimize the field development, minimizing the risks and reducing the capital expenditure (CAPEX) initially planned. This paper presents the first four Buzios subsea system developments, highlighting some of the technological achievements applied in the field, as the first wide application of 8" Internal Diameter (ID) flexible production pipes for ultra-deep water, leading to faster ramp-ups and higher production flowrates. It describes how the supply chain strategy provided flexibility to cover the remaining project uncertainties, and reports the optimizations carried out in flexible riser systems and subsea layouts. The flexible risers, usually installed in lazy wave configurations at such water depths, were optimized reducing the total buoyancy necessary. For water injection and service lines, the buoyancy modules were completely removed, and thus the lines were installed in a free-hanging configuration. Riser configuration optimizations promoted a drop of around 25% on total riser CAPEX and allowed the riser anchor position to be placed closer to the floating production unit, promoting opportunities for reducing the subsea tieback lengths. Standardization of pipe specifications and the riser configurations allowed the projects to exchange the lines, increasing flexibility and avoiding riser interference in a scenario with multiple suppliers. Furthermore, Buzios was the first ultra-deep-water project to install a flexible line, riser, and flowline, with fully Controlled Annulus Solution (CAS). This system, developed by TechnipFMC, allows pipe integrity management from the topside, which reduces subsea inspections. As an outcome of the technological improvements and the optimizations applied to the Buzios subsea system, a vast reduction in subsea CAPEX it was achieved, with a swift production ramp-up.

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.

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.

Successful production application of 3‐D amplitude variation with offset: The lessons learned

Geophysics ◽  
2002 ◽  
Vol 67 (2) ◽  
pp. 379-390 ◽  
Author(s):  
William L. Soroka ◽  
Thomas J. Fitch ◽  
Kirk H. Van Sickle ◽  
Philip D. North
Keyword(s):  
Gas Production ◽  
Lessons Learned ◽  
Seismic Survey ◽  
Total Production ◽  
Old Field ◽  
Amplitude Variation ◽  
Initial Flow ◽  
Amplitude Variation With Offset ◽  
Field Development ◽  
Infill Drilling

Amplitude variation with offset (AVO) analysis was successfully performed on a 3‐D prestack seismic volume. Important conclusions were that AVO results could improve field development and production, that 3‐D AVO results were more useful than 2‐D AVO results, and that reliable AVO results could be generated on land. The AVO results were used to help develop an infill drilling program to increase production. AVO information lowered the risk of finding hydrocarbons by helping to identify seismic events that had a higher probability of being gas‐saturated sands. The 3‐D seismic survey covered known gas zones and potential new reserves. The AVO calibration work showed that positive AVO gas responses (classes 2 and 3) were observed for 90% of the zones associated with known production. One 15‐ft‐thick gas reservoir below seismic resolution did not give a positive AVO anomaly. A well drilled to an untested zone displaying a positive AVO anomaly encountered commercial quantities of gas. Production from this new zone at the initial flow rate increased the total production rate in this 25‐year‐old field by >50%. The AVO method was shown to be applicable onshore and to provide useful results in more consolidated geologic environments with classes 2 and 3 AVO responses. For the successful use of AVO, greater effort and extra care in acquisition and processing were needed than in a normal seismic program.

scholarly journals Current state of the gas industry of the republic of kazakhstan

2021 ◽  
pp. 201-208
Author(s):  
Z. A. Imangozhina
Keyword(s):  
Natural Gas ◽  
Moving Average ◽  
Gas Production ◽  
Gas Pipelines ◽  
Gas Field ◽  
Gas Industry ◽  
The World ◽  
The Republic ◽  
Pass Through ◽  
Sphere Of Influence

The Republic of Kazakhstan possesses large reserves of natural resources. Gas is one of the most demanded energy resources in the world today. Kazakhstan is one of the 30 leading countries in terms of gas reserves and production, while constantly increasing its production potential and expanding its sphere of influence in the gas field in the world. In percentage terms, Kazakhstan owns 1.7% of the world's proven natural gas reserves. This article analyzes the indicators of the country's gas industry development. There was prepared a forecast of natural gas production up to 2030, it was made using the Brown model of moving average (CC model). The analysis of indicators of gas transportation through pipelines, such as transit and export, is made. The location on the map plays an important role in the development of the gas industry in Kazakhstan, as gas pipelines connecting Europe and Asia pass through its territory. Transit gas pipelines are used both for gas supplies to the domestic market of the country and for gas exports. The total length of high, medium and low pressure gas pipelines in Kazakhstan is 28,628 km. In addition to positive indicators indicating the stable development of the industry, the factors hindering the development of the gas industry of the Republic of Kazakhstan are identified.

scholarly journals Well-to-Wheel analysis of natural gas for hybrid electric truck application

2021 ◽  
Vol 266 ◽  
pp. 04011
Author(s):  
F. Zhang ◽  
W.B. Nader ◽  
A. Zoughaib ◽  
X. Luo
Keyword(s):  
Life Cycle ◽  
Natural Gas ◽  
Recovery Phase ◽  
Gas Production ◽  
Heavy Duty ◽  
Compressed Natural Gas ◽  
Methane Leakage ◽  
Passenger Vehicles ◽  
Co2 Equivalent ◽  
Hybrid Electric

Compressed natural gas as an alternative fuel obviously has a great potential to reduce the greenhouse gas emissions. Although several studies on the life cycle are quite comprehensive for passenger vehicles, it is problematic to apply these results to heavy-duty electric hybrid trucks. This paper describes the Well-to-Wheel methodology for environmental impact from the gas production to its final application. The CO2 equivalent emissions and the methane leakage point will be identified at the end. The results indicate that compressed natural gas-based trucks have 18.7% less CO2 equivalent emissions than diesel-based ones. However, this benefit may be affected by methane leakage, particularly, in the recovery phase. Reducing methane emissions upstream could be an opportunity to optimize the pollution performance of heavy hybrid electric trucks.

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 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

scholarly journals Dual hydrocarbon–geothermal energy exploitation: potential synergy between the production of natural gas and warm water from the subsurface

2019 ◽  
Vol 98 ◽  
Author(s):  
Jeroen van der Molen ◽  
Elisabeth Peters ◽  
Farid Jedari-Eyvazi ◽  
Serge F. van Gessel
Keyword(s):  
Natural Gas ◽  
Financial Risk ◽  
Net Present Value ◽  
Gas Production ◽  
Added Value ◽  
Reservoir Properties ◽  
Gas Field ◽  
Gas Recovery ◽  
Water Breakthrough ◽  
High Standards

Abstract The decline of domestic natural gas production, increasing dependency on gas imports and lagging development of renewable energy production may pose serious challenges to the current high standards of secure energy supply in the Netherlands. This paper examines synergy between hydrocarbon- and geothermal exploitation as a means to reinforce energy security. The Roden gas field is used as an example to demonstrate potential delay of water breakthrough in the gas well and a resulting increase of recovered gas (up to 19%), by positioning of a geothermal doublet in the water leg of the gas field. The reservoir simulations show that the total increase of gas production primarily depends on the amount of aquifer support. An optimal configuration of gas- and geothermal wells is key to maximise gas recovery and strongly depends on the distribution of reservoir properties. The study also reveals that this option can still be beneficial for gas fields in a late stage of production. Net Present Value calculations show that the added value from the geothermal doublet on total gas production could lead to an early repayment of initial investments in the geothermal project, thereby reducing the overall financial risk. If no subsidies are taken into account, the additional profits can also be used to finance the geothermal project up to break-even level within 15 years. However, this comes with a cost as the additional profits from improved gas recovery are significantly reduced.

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