Optimization Proration Research in Volcanic Reservoir in Songnan Gas Field

2012 ◽  
Vol 616-618 ◽  
pp. 858-863
Author(s):  
Hua Liu ◽  
Zhi Liang Shi ◽  
Xiang Fang Li ◽  
Yun Cong Gao
Keyword(s):  
Production Method ◽  
Gas Production ◽  
Production Optimization ◽  
Gas Field ◽  
Field Development ◽  
Volcanic Reservoir ◽  
Geological Conditions ◽  
High Efficient ◽  
Single Well ◽  
Line Technology

Volcanic Reservoir in Songnan gas field is now in the early development, the scale of the single well and stable development put forward important requirements, reasonable match is efficient in gas reservoir development of the key. According to the geological conditions of volcanic rock reservoirs special, in the full analysis of the dynamic and static data, and on the basis of preliminary mastered the gas, water relations; And the use of gas production method, the method of curve, economic boundary method and the improvement of horizontal Wells method of the gas line technology reasonable production optimization and argument, high efficient and economical for gas field development.

scholarly journals Evaluation of natural gas production optimization in Kailashtila gas field in Bangladesh using decline curve analysis method

2015 ◽  
Vol 50 (1) ◽  
pp. 29-38 ◽  
Author(s):  
MS Shah ◽  
HMZ Hossain
Keyword(s):  
Production System ◽  
Gas Production ◽  
Curve Analysis ◽  
Production Optimization ◽  
Reservoir Pressure ◽  
Gas Field ◽  
Wellhead Pressure ◽  
Decline Curve Analysis ◽  
Decline Curve ◽  
Overall Performance

Decline curve analysis of well no KTL-04 from the Kailashtila gas field in northeastern Bangladesh has been examined to identify their natural gas production optimization. KTL-04 is one of the major gas producing well of Kailashtila gas field which producing 16.00 mmscfd. Conventional gas production methods depend on enormous computational efforts since production systems from reservoir to a gathering point. The overall performance of a gas production system is determined by flow rate which is involved with system or wellbore components, reservoir pressure, separator pressure and wellhead pressure. Nodal analysis technique is used to performed gas production optimization of the overall performance of the production system. F.A.S.T. Virtu Well™ analysis suggested that declining reservoir pressure 3346.8, 3299.5, 3285.6 and 3269.3 psi(a) while signifying wellhead pressure with no changing of tubing diameter and skin factor thus daily gas production capacity is optimized to 19.637, 24.198, 25.469, and 26.922 mmscfd, respectively.Bangladesh J. Sci. Ind. Res. 50(1), 29-38, 2015

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.

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.

scholarly journals Short-Term Model-Based Production Optimization for a Gas Field in North Africa

2018 ◽  
Vol 10 (2) ◽  
pp. 65
Author(s):  
Arnaud Hoffmann
Keyword(s):  
Piecewise Linear ◽  
Treatment Plant ◽  
Gas Production ◽  
Production Optimization ◽  
Mixed Integer ◽  
Short Term ◽  
Gas Reservoir ◽  
Gas Field ◽  
Gas Treatment ◽  
Model Based

 This paper presents a model-based optimization solution suitable for short-term production optimization of large gas fields with wells producing into a common surface network into a shared gas treatment plant. The proposed methodology is applied to a field consisting of one dry gas reservoir with a CO2 content of 7.3% and one wet gas reservoir with a CO2 content of 2.8% and initial CGR of 15 stb/MMscf. 23 wells are producing, and all gas production is processed in a common gas treatment plant where condensates and CO2 are extracted from the reservoir gas. The final sales gas must honor compositional constraints (CO2 content and heating value). The proposed solution consists of a bi-level optimization algorithm. A Mixed Integer Linear Programming (MILP) formulation of the optimization problem is solved, assuming some key parameters in the gas plant to be constant. Hydraulic performances of the system, approximated using SOS2 piecewise linear models, and condensates and CO2 extraction, captured using simplified models, are included in the MILP. After solving the MILP, the values of the key parameters are calculated using a full simulation model of the gas plant and the new values are substituted in the MILP input data. This iterative procedure continues until convergence is achieved. Results show that the proposed methodology can find the optimum choke openings for all wells to maximize the total gas rate while honoring numerous surface constraints. The solution runs in 30 sec. and an average of 3-4 iterations is needed to achieve convergence. It is therefore a suitable solution for short-term production optimization and daily operations.

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

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.

scholarly journals Production optimization in well-6 of Habiganj gas field, Bangladesh: a prospective application of Nodal analysis approach

2020 ◽  
Vol 10 (8) ◽  
pp. 3557-3568
Author(s):  
Md. Shaheen Shah ◽  
Md Hafijur Rahaman Khan ◽  
Ananna Rahman ◽  
Stephen Butt
Keyword(s):  
Optimization Technique ◽  
Gas Production ◽  
Production Optimization ◽  
Vertical Wells ◽  
Gas Reservoirs ◽  
Gas Field ◽  
Nodal Analysis ◽  
Prospective Application ◽  
Overall Performance ◽  
Inflow Performance

Abstract The overall performance of gas reservoirs and the optimization of production, as well as its sensitivity analysis, are affected by several factors such as reservoir pressure, well configuration and surface facilities. The Habiganj well no. 06 (HBJ-06) is one of the significant gas-producing vertical wells of the Habiganj gas field, currently producing 14.963 MMscfd of natural gas from the upper gas sand. The widely used Nodal analysis is an optimization technique to improve the performance and was applied for the HBJ-06 to increase its production rate by optimizing manners. By this analysis, each component starting from the reservoir to the outlet pressure of the separator was identified as a resistance in the system by evaluating their inflow performance relationship and vertical lift performance. The F.A.S.T. VirtuWell™ software package was used to perform this analysis, where the declinations of wellhead pressures were suggested as 1300, 1200, 1100 and 1000 psi(a) without any modification of the tubing diameter and skin factor. Hence, the respective optimized rates of the daily gas production were increased to 38.481, 40.993, 43.153 and 46.016 MMscfd. At the same time, the optimized condensate gas ratio was calculated as 0.07, 0.06, 0.06 and 0.05, associated with the optimized condensate water ratio of 0.11, 0.10, 0.09 and 0.08, respectively.

Sign in / Sign up

Export Citation Format

Share Document