World First Commercial Application of Permanent Interventionless Monitoring Using Intelligent Inflow Gas Tracer Technology

2021 ◽  
Author(s):  
Khairil Faiz Abdul Aziz ◽  
Azreen Mustafa ◽  
Paul Wong ◽  
Marie Wurtz ◽  
Edmund Leung ◽  
...  
Keyword(s):  
Feasibility Studies ◽  
Oil Reservoirs ◽  
Commercial Application ◽  
Gas Field ◽  
Full Field ◽  
Field Development ◽  
The North ◽  
Water Breakthrough ◽  
Sampling Campaign ◽  
Gas Tracer

Abstract Over the past decade, commercially available inflow tracers have been increasingly used to permanently monitor lower completions without the need for intervention. They have been designed to release selectively to oil or water, typically for clean-up verification, inflow quantification and identifying the location of water breakthrough in oil reservoirs. Naturally, there has been an industry demand and requirement to develop inflow gas tracers to monitor gas reservoirs and identifying the location of gas breakthrough in oil reservoirs. In a green field development, it is important to obtain as much measurements as possible to understand completion efficiency and guide reservoir management decisions. This paper presents the first commercial installation of inflow gas tracer technology that has been deployed in a dry gas field by HESS Malaysia in open hole stand-alone screen completions. It discusses the original monitoring objectives of this application in a full field development and how they evolved due to the gas tracer capabilities and the need for early well and field information. This paper will also discuss the retrofit screen design that allowed the gas tracers embedded in a polymer matrix called gas systems (GS) to be installed inside premium mesh screens. At the wellsite, sampling campaign adjustments were executed depending on the flowing conditions during the clean-up, restarts to obtain relative flow contribution and inflow performance under multi-rate testing conditions. Using a structured approach, the inflow gas monitoring project included feasibility studies, well candidate selection, lessons learnt and developed best practices based on installations in six producing wells in the North Malay Basin (NMB).

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.

Achieving Cementing Improvement in Horizontal Tight Gas Field Development

2015 ◽  
Author(s):  
Pungki Ariyanto ◽  
Mohamed.A.. A. Najwani ◽  
Yaseen Najwani ◽  
Hani Al Lawati ◽  
Jochen Pfeiffer ◽  
...  
Keyword(s):  
Tight Gas ◽  
Cement Slurry ◽  
Tight Sandstone ◽  
Gas Field ◽  
Full Field ◽  
Field Development ◽  
Horizontal Drain ◽  
Tight Reservoir ◽  
Design For All ◽  
Zonal Isolation

Abstract This paper outlines how a drilling team is meeting the challenge of cementing a production liner in deep horizontal drain sections in a tight sandstone reservoir. It is intended to show how the application of existing technologies and processes is leading to performance gain and improvements in cementing quality. The full field development plan of the tight reservoir gas project in the Sultanate of Oman is based on drilling around 300 wells targeting gas producing horizons at measured depths of around 6,000m MD with 1,000m horizontal sections. Effective cement placement for zonal isolation is critical across the production liner in order to contain fracture propagation in the correct zone. The first few attempts to cement the production liner in these wells had to overcome many challenges before finally achieving the well objectives. By looking at the complete system, rather than just the design of the cement slurry, the following criteria areas were identified: –Slurry design–Mud removal and cement slurry placement–Liner hanger and float equipment Improvements have been made in each of these areas, and the result has been delivery of a succesfully optimised liner cementing design for all future horizontal wells.

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.

Implications of accurate geomechanical modelling and systematic core testing for sanding evaluation and sand control decisions – a case study from Perth Basin

2020 ◽  
Vol 60 (1) ◽  
pp. 267
Author(s):  
Sadegh Asadi ◽  
Abbas Khaksar ◽  
Mark Fabian ◽  
Roger Xiang ◽  
David N. Dewhurst ◽  
...  
Keyword(s):  
Management Strategies ◽  
Mechanical Tests ◽  
Well Test ◽  
Sand Production ◽  
Gas Field ◽  
Stress Regime ◽  
Full Field ◽  
Field Development ◽  
Sand Control ◽  
Rock Mechanical Properties

Accurate knowledge of in-situ stresses and rock mechanical properties are required for a reliable sanding risk evaluation. This paper shows an example, from the Waitsia Gas Field in the northern Perth Basin, where a robust well centric geomechanical model is calibrated with field data and laboratory rock mechanical tests. The analysis revealed subtle variations from the regional stress regime for the target reservoir with significant implications for sanding tendency and sand management strategies. An initial evaluation using a non-calibrated stress model indicated low sanding risks under both initial and depleted pressure conditions. However, the revised sanding evaluation calibrated with well test observations indicated considerable sanding risk after 500 psi of pressure depletion. The sanding rate is expected to increase with further depletion, requiring well intervention for existing producers and active sand control for newly drilled wells that are cased and perforated. This analysis indicated negligible field life sanding risk for vertical and low-angle wells if completed open hole. The results are used for sand management in existing wells and completion decisions for future wells. A combination of passive surface handling and downhole sand control methods are considered on a well-by-well basis. Existing producers are currently monitored for sand production using acoustic detectors. For full field development, sand catchers will also be installed as required to ensure sand production is quantified and managed.

The Auk Field, Block 30/16, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 483-496 ◽  
Author(s):  
Nigel H. Trewin ◽  
Steven G. Fryberger ◽  
Helge Kreutz
Keyword(s):  
Lower Cretaceous ◽  
Upper Cretaceous ◽  
Cross Flow ◽  
Full Field ◽  
Western Margin ◽  
Reservoir Architecture ◽  
The North ◽  
Water Breakthrough ◽  
Artificial Lift ◽  
Year 2000

AbstractThe Auk Field is located in Block 30/16 at the western margin of the Central Graben. Block 30/16 was awarded in June 1970 to Shell/Esso, and the discovery well 30/16-1 spudded in September 1970. The well found oil in a complex horst block sealed by Upper Cretaceous chalk and Tertiary claystones. The field contained an original oil column of up to 400 ft within Rotliegend sandstones, Zechstein dolomites, Lower Cretaceous breccia and Upper Cretaceous chalk. Production by natural aquifer drive commenced from a steel platform in 1976, initially from the Zechstein carbonates and now predominantly from the Rotliegend sandstone. Artificial lift was installed in 1988 helping to maintain production at economic levels past the year 2000. A complex reservoir architecture with cross flow between the Rotliegend and Zechstein reservoirs, a strong aquifer causing early water breakthrough via faults, and a limited seismic definition led to significant production variations from the initial forecasts. Equally important for the field, horizontal well technology opened up additional reserves and accelerated production from the complex Rotliegend reservoir; the most recent volumetric estimate for the total field predicts an ultimate recovery of 151 MMBBL for the existing wells from a STOIIP of 795 MMBBL. Full field reservoir simulation and 3D seismic data acquisition took place since mid 1980s but only recently resulted in a satisfactory understanding of the reservoir behaviour.The field is situated about 270 km ESE from Aberdeen in 240-270 ft of water. It covers a tilted horst block with an area of 65 km2, located at the western margin of the Central Graben. The Auk horst is bounded on the west by a series of faults with throws of up to 1000 ft, the eastern boundary fault has a throw of 5000 ft in the north reducing in throw southwards. The best reservoir lithology in the Zechstein is a vuggy fractured dolomite, and in the Rotliegend dune slipface sandstones provide the majority of the production. Both reservoirs and the overlying Lower Cretaceous breccia shared a common FWL at 7750 ft TVDss. The 38° API oil with a GOR of 190 SCF/STB was sourced from organic-rich Kimmeridge Clay.

The Leman Field, Blocks 49/26, 49/27, 49/28, 53/1, 53/2, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 451-458 ◽  
Author(s):  
A. P. Hillier ◽  
B. P. J. Williams
Keyword(s):  
North Sea ◽  
Old Field ◽  
Gas Field ◽  
Field Development ◽  
Dune Sands ◽  
The North ◽  
The North Sea ◽  
To Come ◽  
The Uk ◽  
Estimated Ultimate Recovery

AbstractDiscovered in 1966 and starting production in 1968, Leman was the second gas field to come into production in the UK sector of the North Sea. It is classified as a giant field with an estimated ultimate recovery of 11 500 BCF of gas in the aeolian dune sands of the Rotliegend Group. The field extends over five blocks and is being developed by two groups with Shell and Amoco being the operators. Despite being such an old field development drilling is still ongoing in the field with the less permeable northwest area currently being developed.

scholarly journals DYNAMICS OF ZOOBENTHOS DEVELOPMENT WITHIN THE WATER AREA OF THE YURI KORCHAGIN FIELD IN THE NORT PART OF THE CASPIAN SEA

2018 ◽  
pp. 89-97
Author(s):  
Semen Nikolaevich Studnikov ◽  
Lyubov Vasilievna Malinovskaya ◽  
Alexey Vladimirovich Kuzin
Keyword(s):  
Population Density ◽  
Benthic Invertebrates ◽  
Caspian Sea ◽  
Water Area ◽  
The Caspian Sea ◽  
Survey Period ◽  
Gas Field ◽  
Field Development ◽  
The North ◽  
North Part

One of the main purposes of the monitoring studies is a long-term research of benthic communities of the north part of the Caspian Sea. Analysis of quantitative and qualitative characteristics is the only means to formulate main laws of the development of benthic biocenosis in terms of enhanced oil and gas field development, as well as to provide a forecast of the state of the fields and of the human impact on them. In the survey period, from 2014 to 2016, 43 species of benthic invertebrates, namely 2 species of Annelida, 32 species of Crustacea and 9 species of Mollusca, were identified as the result of zoobenthos development study. In that period, total average population density of the benthic fauna within the Yuri Korchagin field water area made 6 716 organisms per square meter, while the general average biomass constituted 77.324 grams per square meter. During the whole period of the research such zoobenthos species as Crustaceans and mainly Gammarids, including Ch. Ischnus and St. similis , dominated in terms of population density. As to biomass, the most abundant zoobenthos species were molluscs - Mediterranean species M. lineatus and A. ovata with D. protracta - a marine species - dominating in different years. Zoobenthos diversity, quantity fluctuations and dominance of given species in biomass and population density at certain stations of the studied water area were linked principally to the water salinity, type of soil and food resources availability. The study of benthic invertebrates showed that Yuri Korchagin field area in the north part of the Caspian Sea is characterized by a high development of euryhaline and marine benthic invertebrates.

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