scholarly journals Integrated Field Development Plans of Akkas Gas Field

2020 ◽  
Vol 10 (3) ◽  
pp. 102-122
Author(s):  
Dr. Jalal A. Al-Sudani ◽  
Eng. Adnan N. Sajet ◽  
Eng. Jalal Ahmed ◽  
Eng. Mohamed Enad ◽  
Dr. Abdul-Hussain H. Al-Shibly ◽  
...  
Keyword(s):  
Net Present Value ◽  
Planning Process ◽  
Development Planning ◽  
Gas Production ◽  
Recovery Factor ◽  
Western Desert ◽  
Discounted Cash Flow ◽  
Gas Field ◽  
Field Development ◽  
Development Plans

Akkas gas field is the biggest natural gas field in Iraq that is located in the western desert area. The field contains around (9 BSCF) of approved gas reserve from the conventional rock source. This paper presents field development planning process combined with economic analysis comprises, the number of wells that yields in maximum net present value (NPV), the recovery factor and raw gas production rates for the total number of suggested wells that have been estimated, as well as the cumulative gas produced with time. The development plans were elaborated concerning different types of well geometries and operational constraints. Full comparison analysis for all presented plans regarding NPV, recovery factor, discounted cash flow versus production time, forecasted production rate, as well as forecasted cumulative production with time have been presented. Sensitivity analysis has been made to determine well and reservoir controlling parameters that leads for best operating field development plans. The study shows the effectiveness of horizontal well type compared with vertical wells; as well as, the effect of reservoir permeability on field development plans, the results show that the field could be operated at target plateau rates of (250, 500 and 750 MMSCF/D). It also shows the superior effect of stimulation processes in increasing the NPV and field recovery factor using less number of wells

scholarly journals Integrated gas field development: The Anjum story

2001 ◽  
Vol 80 (1) ◽  
pp. 95-102
Author(s):  
F.J. Hollman
Keyword(s):  
Development Planning ◽  
Gas Production ◽  
Oil Field ◽  
Well Performance ◽  
Gas Field ◽  
Extensive Experience ◽  
Modeling Tools ◽  
Gas Treatment ◽  
Field Development ◽  
Development Plans

AbstractIn contrast to oil field development, gas field development requires tight integration of subsurface, surface and economic issues due to the difficulty of storing surplus produced gas and the large effect of the back-pressures in a surface network on the individual well performance. As a major gas supplier the Shell Group, and in particular NAM, has extensive experience in this field.The gas production from onshore fields in the North Friesland area is a recent NAM development. A 10 million cubic meter per day LTS gas treatment installation located near the village of Anjum came on stream in 1997. Production initially started from 3 wells in 2 fields to deliver gas to the Gasunie grid at Grijpskerk. The total area comprises 10 fields and 4 remaining prospects and is planned to be fully developed by the year 2001, using wet gas pipelines to route the production to either the Anjum LTS installation or the Grijpskerk SilicaGel installation.The Rotliegend reservoirs in this part of the Netherlands are very heterogeneous and require a more detailed subsurface simulation than feasible with the standard NAM tool for gas field development (GENREM). In addition, the area is close to the Waddenzee and based on extensive ecological research, NAM uses a stringent, self-imposed ecological constraint, whilst evaluating the development plans for this area. Detailed subsidence studies have been run using subsidence-modeling tools, which run under a software user-interface called FrontEnd, an in-house development by the Shell Group. Also running under this interface is an application for gas field development called Gas Field Planning Tool (GFPT). GFPT combines a detailed subsurface simulator with a surface simulator using a development planning module, which handles economic and operational aspects of the integrated model. Lastly, the interface gives access to a powerful command language and a mathematical toolbox, which can be used to define almost any missing functionality.Making use of the flexibility offered by the FrontEnd interface and with help from available expertise in RTS (Shell Rijswijk), an integrated GFPT model was built, which not only incorporates operational and economic constraints, but also does optimization and subsidence analysis. The model is used to evaluate all development options and scenarios for this area in a consistent manner. Therefore, all proposed development plans are optimized within all applied constraints whether they are related to surface, subsurface, economic, or environmental aspects.Production history and well performance are very close to those predicted by these detailed models, which will allow accurate prediction of future field performance and subsidence.

scholarly journals The Waitsia Field, onshore North Perth Basin, Western Australia

2016 ◽  
Vol 56 (1) ◽  
pp. 29 ◽  
Author(s):  
Neil Tupper ◽  
Eric Matthews ◽  
Gareth Cooper ◽  
Andy Furniss ◽  
Tim Hicks ◽  
...  
Keyword(s):  
Flow Characteristics ◽  
Development Planning ◽  
Upper Permian ◽  
Depth Interval ◽  
Lower Permian ◽  
Minimal Processing ◽  
Gas Field ◽  
Full Field ◽  
Field Development ◽  
Primary Porosity

The Waitsia Field represents a new commercial play for the onshore north Perth Basin with potential to deliver substantial reserves and production to the domestic gas market. The discovery was made in 2014 by deepening of the Senecio–3 appraisal well to evaluate secondary reservoir targets. The well successfully delineated the extent of the primary target in the Upper Permian Dongara and Wagina sandstones of the Senecio gas field but also encountered a combination of good-quality and tight gas pay in the underlying Lower Permian Kingia and High Cliff sandstones. The drilling of the Waitsia–1 and Waitsia–2 wells in 2015, and testing of Senecio-3 and Waitsia-1, confirmed the discovery of a large gas field with excellent flow characteristics. Wireline log and pressure data define a gross gas column in excess of 350 m trapped within a low-side fault closure that extends across 50 km2. The occurrence of good-quality reservoir in the depth interval 3,000–3,800 m is diagenetically controlled with clay rims inhibiting quartz cementation and preserving excellent primary porosity. Development planning for Waitsia has commenced with the likelihood of an early production start-up utilising existing wells and gas processing facilities before ramp-up to full-field development. The dry gas will require minimal processing, and access to market is facilitated by the Dampier–Bunbury and Parmelia gas pipelines that pass directly above the field. The Waitsia Field is believed to be the largest conventional Australian onshore discovery for more than 30 years and provides impetus and incentive for continued exploration in mature and frontier basins. The presence of good-quality reservoir and effective fault seal was unexpected and emphasise the need to consider multiple geological scenarios and to test unorthodox ideas with the drill bit.

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.

Data Analytics into Hydraulic Modelling for Better Understanding of Well/Surface Network Limits, Proactively Identify Challenges and, Provide Solutions for Improved System Performance in the Greater Burgan Field

2021 ◽  
Author(s):  
Qasem Dashti ◽  
Saad Matar ◽  
Hanan Abdulrazzaq ◽  
Nouf Al-Shammari ◽  
Francy Franco ◽  
...  
Keyword(s):  
Production Management ◽  
Planning Process ◽  
System Optimization ◽  
Development Planning ◽  
Operating Conditions ◽  
Flow Assurance ◽  
Operational Parameters ◽  
Field Development ◽  
Hydraulic Models ◽  
Surface Network

Abstract A network modeling campaign for 15 surface gathering centers involving more than 1800 completion strings has helped to lay out different risks on the existing surface pipeline network facility and improved the screening of different business and action plans for the South East Kuwait (SEK) asset of Kuwait Oil Company. Well and network hydraulic models were created and calibrated to support engineers from field development, planning, and operations teams in evaluating the hydraulics of the production system for the identification of flow assurance problems and system optimization opportunities. Steady-state hydraulic models allowed the analysis of the integrated wells and surface network under multiple operational scenarios, providing an important input to improve the planning and decision-making process. The focus of this study was not only in obtaining an accurate representation of the physical dimension of well and surface network elements, but also in creating a tool that includes standard analytical workflows able to evaluate wells and surface network behavior, thus useful to provide insightful predictive capability and answering the business needs on maintaining oil production and controlling unwanted fluids such as water and gas. For this reason, the model needs to be flexible enough in covering different network operating conditions. With the hydraulic models, the evaluation and diagnosis of the asset for operational problems at well and network level will be faster and more effective, providing reliable solutions in the short- and long-terms. The hydraulic models enable engineers to investigate multiple scenarios to identify constraints and improve the operations performance and the planning process in SEK, with a focus on optimal operational parameters to establish effective wells drawdown, evaluation of artificial lifting requirements, optimal well segregation on gathering centers headers, identification of flow assurance problems and supporting production forecasts to ensure effective production management.

Feasibility Study on the Implementation of CO2-EOR Coupled with Sequestration in Trinidad via Reservoir Simulation

2014 ◽  
Author(s):  
J.. Narinesingh ◽  
D. V. Boodlal ◽  
D.. Alexander
Keyword(s):  
Primary Production ◽  
Oil Recovery ◽  
Net Present Value ◽  
Fluid Model ◽  
Gas Production ◽  
Economic Feasibility ◽  
Utilization Rate ◽  
Optimum Number ◽  
Field Development ◽  
Co2 Eor

Abstract The paper seeks to assess the technical and economic feasibility of implementing carbon dioxide enhanced oil recovery (CO2 EOR) in Trinidad and Tobago from flue gas production whilst mitigating the effect of greenhouse gases via CO2 sequestration. An existing power plant in Trinidad was selected as the CO2 source. As such, actual CO2 volumes and properties were found and used in this analysis. However, a hypothetical field was chosen as the appropriate sink, which can be analogous to a field in onshore Trinidad. A detailed reservoir model was built using the compositional fluid model CMG-GEM. Various scenarios were simulated to determine the optimum number of producers for primary production and the best location of the injectors for CO2 EOR. The optimum number of producers for the reservoir during primary production was found. In addition, the most favorable location of the injector to avoid early breakthrough and increase oil recovery was also determined. Many key parameters were reported from this investigation. These included OIIP, forecasted production and primary recovery. After primary production, CO2 EOR was then implemented with the use of the reservoir and fluid models and the additional recovery is reported. Other Key CO2-EOR parameters such as CO2 utilization rate and total sequestered CO2 were also quantified. Though a hypothetical reservoir was used, all associated data were defined and once an actual reservoir is known, the same technically rigid methodology can be applied. The OIIP was found to be 6.74 MMSTB for the selected reservoir. Based on an economic net present value (NPV) assessment, the optimum number of production wells for field development was found to be 3. At the end of primary production from these three wells (with 2.375 in. tubing), a total of 1.83 MMSTB were produced. This corresponded to a primary recovery factor of 27.2% over 4 years and 2 months. For CO2 EOR coupled with sequestration, these three wells were manipulated and used as 1 injector and 2 producers. CO2 EOR led to another 1.07 MMSTB of recovery for a total of 2.9 MMSTB (43.04% Recovery) for the ten year life of the project. A total of 5427 MMSCF (287 000 tons) of CO2 was sequestered in the reservoir (40.39% Storage) at an injection pressure of 1400 psi.

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.

SUB-SURFACE UNCERTAINTY IN OIL FIELDS: LEARNINGS FROM EARLY PRODUCTION OF LEGENDRE OIL FIELDS

2003 ◽  
Vol 43 (1) ◽  
pp. 401
Author(s):  
R. Seggie ◽  
F. Jamal ◽  
A. Jones ◽  
M. Lennane ◽  
G. McFadzean ◽  
...  
Keyword(s):  
Planning Process ◽  
Development Planning ◽  
Oil Field ◽  
Production Performance ◽  
Oil Fields ◽  
High Rate ◽  
Secondary Development ◽  
North West ◽  
Field Development ◽  
Small Primary

The Legendre North and South Oil Fields (together referred to as the field) have been producing since May 2001 from high rate horizontal wells and had produced 18 MMBBL by end 2002. This represents about 45% of the proven and probable reserves for the field.Many pre-drill uncertainties remain. The exploration and development wells are located primarily along the crest of the structure, leaving significant gross rock volume uncertainty on the flanks of the field. Qualitative use of amplitudes provides some insight into the Legendre North Field but not the Legendre South Field where the imaging is poor. The development wells were drilled horizontally and did not intersect any fluid contacts.Early field life has brought some surprises, despite a rigorous assessment of uncertainty during the field development planning process. Higher than expected gas-oil ratios suggested a saturated oil with small primary gas caps, rather than the predicted under-saturated oil. Due to the larger than expected gas volumes, the gas reinjection system proved to have inadequate redundancy resulting in constrained production from the field. The pre-drill geological model has required significant changes to reflect the drilling and production results to date. The intra-field shales needed to be areally much smaller than predicted to explain well intersections and production performance. This is consistent with outcrop analogues.Surprises are common when an oil field is first developed and often continue to arise during secondary development phases. Learnings, in the context of subsurface uncertainty, from other oil fields in the greater North West Shelf are compared briefly to highlight the importance of managing uncertainty during field development planning. It is important to have design flexibility to enable facility adjustments to be made easily, early in field life.

Using innovation to lower gas gathering costs for unconventional projects

2015 ◽  
Vol 55 (2) ◽  
pp. 406
Author(s):  
Vishnu Nair
Keyword(s):  
Shale Gas ◽  
Economic Transition ◽  
Low Cost ◽  
Cost Savings ◽  
Development Planning ◽  
Gas Production ◽  
Significant Shift ◽  
Functional Requirements ◽  
Project Development ◽  
Field Development

Moving from conventional to unconventional gas project development requires a significant shift in approach. This presents challenges for operators making this transition, including standards and specifications being mis-matched to functional requirements, the need for robust surface and subsurface field development planning, lack of infrastructure, high construction and procurement costs and the scarcity of supply chain and logistics support. In their need to prove up sufficient reserves in time for downstream LNG plant operations, coal seam gas (CSG) players have neglected the development of appropriate standards, specifications and contracting and procurement strategies that consider how upstream costs can be minimised. This can impact project viability in a high-cost, low-productivity environment. The requirement of shale gas development for continual expansion also presents challenges compared to conventional project development. Adopting a factory approach can ensure a smooth and economic transition through the phase of continual shale gas production across the life of individual wells and through field expansion. Using case studies, this extended abstract describes how innovation can be applied across the gas-gathering development phase of unconventional projects to achieve significant cost savings. Key innovative opportunities include: Maximising modularise construction and operation to reduce the construction schedule and maximise onsite productivity Relocatable, interchangeable, standardised skid designs (design kit approach). Standard modules sized to maximise container volumes (and they minimise freight costs) Low-cost design Asian and Australian fabrication. Fit-for-purpose technology and packages to lower operating costs. Design and fabrication to minimise environmental impacts.

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