Offshore Gas Field Development Optimization Study Applied QA/QC Procedure For Models Accuracy And Decision Reliability "Full Field Compositional Simulation Study - Case History"

2007 ◽  
Author(s):  
Lutfi Aref Salameh ◽  
Faisal Al-Jenaibi
Keyword(s):  
Simulation Study ◽  
Case History ◽  
Compositional Simulation ◽  
Gas Field ◽  
Full Field ◽  
Field Development ◽  
Optimization Study ◽  
Study Case

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.

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.

Streamline Technology for the Evaluation of Full Field Compositional Processes; Midale, A Case Study

2005 ◽  
Vol 8 (05) ◽  
pp. 404-417 ◽  
Author(s):  
Robert A. McKishnie ◽  
Shelin Chugh ◽  
Sonja Malik ◽  
Robert G. Lavoie ◽  
Paul J. Griffith
Keyword(s):  
Horizontal Wells ◽  
Pilot Project ◽  
Demonstration Project ◽  
Injection Timing ◽  
Compositional Simulation ◽  
Streamline Simulation ◽  
Reservoir Heterogeneity ◽  
Full Field ◽  
Field Development ◽  
Development Scenarios

Summary Traditionally, the evaluation of CO2-flooding processes is performed with finite-difference compositional-simulation models. However, compositional simulation is impractical for modeling large-scale CO2 floods because of computational run-time restrictions. In cases in which reservoir heterogeneity and fluid mobility dominate the reservoir recovery mechanism, streamline simulation offers a viable alternative to compositional simulation. The"reduced" physics in streamline simulation allows field-scale CO2-flood modeling to be feasible, as long as the streamline pressure/volume/ temperature(PVT) model can be calibrated so that the streamline model will produce accurate results for CO2-injection processes. Using streamline simulation allows for the evaluation of multiple full-field development scenarios that otherwise would not be possible with compositional simulation. The objective of the study was to provide CO2-flood performance forecasts under various full-field development scenarios for the Midale field. This paper focuses on the methodology and results from the 1,000-well,>400,000-gridblock, 45+-year streamline simulation of the Midale field. In particular, it discusses the construction and history match of the full-field model, the calibration of the streamline model with the compositional model, and the development of the full-field CO2 forecasts. Introduction The Midale field, in southeast Saskatchewan, Canada (Fig. 1), was discovered in 1953 and subsequently delineated on 80-acre spacing. The field produced under competitive drainage until unitization in late 1962, after which an inverted nine-spot waterflood scheme was implemented. During the mid-1980s, an extensive vertical infill program was used to modify the waterflood patterns. Horizontal wells in the late 1980s and multi legged perpendicular horizontals in the mid-1990s were used to further improve waterflood conformance. To date, the unit has recovered more than 125 million STB of oil (primarily from waterflood operations), representing approximately 24% original oil in place (OOIP). Recognizing the large volume of oil that would not be recovered by waterflooding operations, a CO2-flood pilot project was initiated in 1984. This project involved the drilling of 10 closely spaced wells in an area 4.4 acres in size and generated an enormous amount of reservoir and geological information. Results from the CO2 pilot project were used to justify the larger-scale Midale CO2-flood demonstration project, a six-pattern CO2 flood located in the southwestern part of the unit that began operations in 1992.Positive results from the Midale CO2 demonstration project were instrumental in justifying the neighboring Weyburn CO2-flood project, which began operations in2000, and they were also key to the technical justification of a full-field Midale CO2 flood. Apache's acquisition of the field in 2000 was followed by an aggressive campaign to increase the recovery through infill drilling with horizontal wells at 20- to 40-acre spacing, increased injection and throughput (by a factor of three), and a review of the feasibility of a full-field CO2 flood. The objective of this study was to assess the commercial CO2-flood potential of the Midale unit within a 5-month study period. Traditionally, a compositional simulator is used to accurately model the pressure-dependent phase behavior of CO2. However, despite advances in computing power and software, compositional simulation is impractical for field-level simulations of large fields such as the Midale unit. An alternative to compositional modeling is streamline simulation. Recent advances in streamline simulation show that in cases in which reservoir heterogeneity and the production/injection coupling dominate, first-order approximations offered by streamline simulation are sufficient for full-field development decisions. Invariably, the development plan is modified as the field is depleted and more information becomes available. Also, full-field streamline simulation allows for optimization of water-alternating-gas (WAG) cycles and pattern-injection timing that would be difficult to evaluate with compositional simulation. The difficulty with streamline simulation is that it lacks the direct PVT model to accurately describe the interaction between the oil and the CO2 at various pressures and temperatures. Detailed compositional models are required when drastic changes in fluid properties occur, such as near the critical point or condensate dropout in retrograde gas reservoirs. When the problem is one of modeling a relatively smooth transition between miscibility and immiscibility at a certain pressure, the modification of a black-oil model by Todd and Longstaff is quite often used because of its significantly faster computational speed.

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).

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