Compaction and Subsidence Assessment to Optimize Field Development Planning for an Oil Field in Sultanate of Oman

2018 ◽  
Author(s):  
Sandeep Mahajan ◽  
Hala Hassan ◽  
Timothy Duggan ◽  
Rakesh Dhir
Keyword(s):  
Development Planning ◽  
Oil Field ◽  
Sultanate Of Oman ◽  
Field Development

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.

DEVELOPMENT PLANNING FOR THE COSSACK AND WANAEA FIELDS

1994 ◽  
Vol 34 (1) ◽  
pp. 92
Author(s):  
G. B. Salter ◽  
W. P. Kerckhoff
Keyword(s):  
Cost Reduction ◽  
Water Injection ◽  
Development Planning ◽  
Oil Field ◽  
Oil Fields ◽  
Oil Reservoirs ◽  
Field Development ◽  
Oil Reserves ◽  
Oil Field Development ◽  
Significant Effort

Development of the Cossack and Wanaea oil fields is in progress with first oil scheduled for late 1995. Wanaea oil reserves are estimated in the order of 32 x 106m3 (200 MMstb) making this the largest oil field development currently underway in Australia.Development planning for these fields posed a unique set of challenges.Key subsurface uncertainties are the requirement for water injection (Wanaea only) and well numbers. Strategies for managing these uncertainties were studied and appropriate flexibility built-in to planned facilities.Alternative facility concepts including steel/concrete platforms and floating options were studied-the concept selected comprises subsea wells tied-back to production/storage/export facilities on an FPSO located over Wanaea.In view of the high proportion of costs associated with the subsea components, significant effort was focussed on flowline optimisation, simplification and cost reduction. These actions have led to potential major economic benefits.Gas utilisation options included reinjection into the oil reservoirs, export for re-injection into North Rankin or export to shore. The latter requires the installation of an LPG plant onshore and was selected as the simplest, safest and the most economically attractive method.

scholarly journals Integrated Study of Production Decline Analysis and Streamline Simulation on Haripur Oil Field

2019 ◽  
Vol 67 (1) ◽  
pp. 47-50
Author(s):  
Mohammad Amirul Islam ◽  
ASM Woobaidullah ◽  
Badrul Imam
Keyword(s):  
Reservoir Simulation ◽  
Oil And Gas ◽  
Development Planning ◽  
Oil Field ◽  
Streamline Simulation ◽  
Field Development ◽  
Drainage Volume ◽  
Simulation Techniques ◽  
Exponential Decline ◽  
Tools And Techniques

In oil and gas industries there are available production data analysis tools and reservoir simulation techniques. Scientists and engineers use these tools and techniques to generate authentic and valuable information on the reservoir for planning and development. In this study production rate decline and streamline reservoir simulation are analyzed integrated way to determine the well life, flow rate, producible reserve, drainage volume and reserve. Well no SY-7 of Haripur oil field produced 0.531 million barrel of oil from 1987 to 1994. Exponential decline rate is matched with production profile and reveals well life of 10 years, producible reserve 0.7 million barrels. In addition, the drainage volume around the well is 158 million cubic feet estimated from the well life by using the streamline simulation, as well as the oil reserve 2 million barrels in the drainage volume is estimated. This reserve information carries value, authenticity and reliability for field development planning. Dhaka Univ. J. Sci. 67(1): 47-50, 2019 (January)

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.

Evaluation of Hydrocarbon Producability Below FWL Onshore Abu Dhabi Oil Field Case Study

2021 ◽  
Author(s):  
Francis Eriavbe ◽  
Abdurahiman Vadakkeveetil ◽  
Mohamad Alkhatib ◽  
Iftikhar Khattak ◽  
Raffik Lazar
Keyword(s):  
Reservoir Characterization ◽  
Data Gathering ◽  
Holistic Approach ◽  
Integrated Approach ◽  
Development Planning ◽  
Oil Field ◽  
Abu Dhabi ◽  
Main Body ◽  
Field Development ◽  
Domain Integration

Abstract Objectives / Scope This paper addresses the field development planning challenges of a green onshore South East Abu Dhabi oil field with limited production data. Tectonic movements have created strike slip faults dissecting the structure and uplifting the main body. Tilting of the flanks has resulted in the accumulation to leak some of its initial hydrocarbon and a rebalancing showing a titled FWL. A novel workflow was used to address the challenging reservoir physics including hydrocarbon below FWL. The paper takes a holistic approach in integrating multiple domains data such as Drilling, Petrophysics, Geology and Reservoir / Production Engineering. Methods, Procedures, Process An integrated approach was adopted to address the complexity and challenges of characterizing and modelling the field with hydrocarbon below FWL. Extensive range of data was collected to contribute to better understanding and evaluation of the field. The producibility of hydrocarbon below FWL have a significant impact on field development planning. The used workflow was specifically suitable to drive subsurface team right reservoir characterization: Improve fluid contacts understanding Explain the log responses The discrepancies between dynamic and static responses De-risk the volumetric uncertainties Results Following an extensive multi-disciplinary technical analysis of all available datasets, the most robust, accurate and reliable reservoir characterization, that can be seamlessly integrated into dynamic reservoir modelling phase. A systematic approach was adopted starting from core measurement and lab visits, drilling data such as mud logs, Petrophysical evaluation of multiple complex physics such as hydrocarbon presence below FWL, micro porous intervals, Micritic minerals and imbibition effect, geological regional understanding of faulted reservoirs, and dynamic data such as formation well tests. The study demonstrated that multi-domain integration played a key role in addressing the complex and challenging reservoir dynamics. Novel / Additive Information Large subsurface uncertainty combined with an extensive domain integration required cutting-edge reservoir de-risking and data gathering to provide the optimal reservoir characterization. These unique workflows can be readily used in similar green fields and will be described in full details in the paper.

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