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Collaborating Authors
Results
Improved Producibility after Delayed Filter Cake Breaker Treatment in the Safaniya Offshore Field in Saudi Arabia
Zubail, M. A. (Saudi Aramco) | Al-Kuait, A. M. (Saudi Aramco) | Al-Yateem, K. S. (Saudi Aramco) | El Bialy, M.. (Halliburton) | Maghrabi, S.. (Halliburton) | Olivares, T.. (Halliburton) | Ezell, R. G. (Halliburton)
Abstract Safaniya is one of largest offshore oil fields located north of Dhahran in Saudi Arabia. It is 50 km by 15 km in size and began production in 1956. Lately, a few wells drilled in this field showed reservoir damage where the production dropped or the well had no flow. Workover operations were performed on six wells and two new wells were drilled. For all eight wells, 6⅛-in. laterals were drilled through the reservoirs with an engineered invert emulsion drilling fluid (RDF). The RDF design was controlled to ensure an acid-soluble, thin, external filter cake with no fines invasion. The vulnerability of the filter cake to be attacked by the acid was fundamental to this RDF design. A delayed filter cake breaker fluid was then designed for use on the 6⅛-in. laterals; this fluid consisted of an organic acid precursor (OAP) and a water wetting additive. The OAP released acid in a delayed manner, whereas the water wetting additive made the oil-based filter cake water wet, to make it vulnerable to acid attack. With this approach, the filter cake was removed uniformly in all subject laterals across the reservoir. The production data on the eight wells treated with the OAP show an improved oil production rate of more than 4,000 B/D for six of the eight wells, which exceeds the key performance indicator (KPI) set for the laterals. In previous years from 2005-10, the six workover wells showed, on average, very low oil production rates (OPR) comparatively. In addition, after the OAP treatment, these six wells show higher well flow head pressures than in 2005–10. The water cut percentage on these laterals was 0 or less than 1, compared to 2005–10, when the water cut percentage varied from 8% to 50% for these workover wells. This paper discusses the workover operation of the six wells and the drilling and delayed stimulation treatment on two new wells in the Safaniya field, including laboratory evaluation, field application and production data.
- Asia > Middle East > Saudi Arabia > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Wasia Formation (0.99)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Safaniya Field (0.94)
- Asia > Middle East > Kuwait > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Safaniya Field (0.94)
- (4 more...)
When Gerald Schotman, Shell's chief technology officer, looks at the unconventional oil and gas business, he sees so many young technologies and "from the perspective a chief technology officer, that is such an opportunity." Shell's list of promising areas for research and development is broad, ranging from creating cheaper, more effective sensors for seismic testing to a new generation of specialized, automated drilling rigs. The goal is always "change that creates value." In natural gas the rewards can be broken down three ways: produce more gas per well now, bring down the costs per well, and reduce the footprint when doing so. The footprint can be defined in many ways: the size of the pads used for drilling multiple wells; the level of emissions; the water used; and the many ways exploration and production can touch the people and the environment, near and far.
- Oceania > Australia > Western Australia > Western Australia > Timor Sea > Browse Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Timor Sea > Browse Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Browse Basin > WA-371-P Permit > Block WA-371-P > Prelude Field > Plover Formation (0.99)
- (4 more...)
Static and Dynamic Estimates of CO2-Storage Capacity in Two Saline Formations in the UK
Jin, M.. (Heriot-Watt University) | Pickup, G.. (Heriot-Watt University) | Mackay, E.. (Heriot-Watt University) | Todd, A.. (Heriot-Watt University) | Sohrabi, M.. (Heriot-Watt University) | Monaghan, A.. (British Geological Survey) | Naylor, M.. (University of Edinburgh)
Summary Estimation of carbon dioxide (CO2)-storage capacity is a key step in the appraisal of CO2-storage sites. Different calculation methods may lead to widely diverging values. The compressibility method is a commonly used static method for estimating storage capacity of saline aquifers: It is simple, is easy to use, and requires a minimum of input data. Alternatively, a numerical reservoir simulation provides a dynamic method that includes Darcy flow calculations. More input data are required for dynamic simulation, and it is more computationally intensive, but it takes into account migration pathways and dissolution effects, so it is generally more accurate and more useful. For example, the CO2-migration plume may be used to identify appropriate monitoring techniques, and the analysis of the trapping mechanism for a certain site will help to optimize well location and the injection plan. Two hypothetical saline-aquifer storage sites in the UK, one in Lincolnshire and the other in the Firth of Forth, were analyzed. The Lincolnshire site has a comparatively simple geology, while the Forth site has a more complex geology. For each site, both static- and dynamic-capacity calculations were performed. In the static method, CO2 was injected until the average pressure reached a critical value. In the migration-monitoring case, CO2 was injected for 15 years, and was followed by a closure period lasting thousands of years. The fraction of dissolved CO2 and the fraction immobilized by pore-scale trapping were calculated. The results of both geological systems show that the migration of CO2 is strongly influenced by the local heterogeneity. The calculated storage efficiency for the Lincolnshire site varied between 0.34% and 0.65% of the total pore-volume, depending on whether the system boundaries were considered open or closed. Simulation of the deeper, more complex Forth geological system gave storage capacities as high as 1.05%. This work was part of the CO2-Aquifer-Storage Site Evaluation and Monitoring (CASSEM) integrated study to derive methodologies for assessment of CO2 storage in saline formations. Although static estimates are useful for initial assessment when fewer data are available, we demonstrate the value of performing dynamic storage calculations and the opportunities to identify mechanisms for optimizing the storage capacity.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Oceania > Australia > Western Australia > Bonaparte Basin > Petrel Basin (0.89)
- Oceania > Australia > Western Australia > Ashmore Cartier Territory > Timor Sea > Bonaparte Basin > Londonderry High > Vulcan Basin > Eclipse Field (0.89)
- Oceania > Australia > Western Australia > Ashmore Cartier Territory > Timor Sea > Bonaparte Basin > Bonaparte Basin > Vulcan Basin > Eclipse Field (0.89)
- (3 more...)
The ability to high-grade gas shales is essential to optimizing completions and maximizing stimulated rock volume (SRV) in the capital-intensive development of the Horn River resource play in northeast British Columbia (NEBC). To assist in optimizing stimulation efforts, seismic data are used to estimate and map four parameters that influence hydraulic fracture effectiveness: rock properties, in-situ stress, natural fractures, and reservoir geometry.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.63)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.47)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation > Seismic Reservoir Characterization > Amplitude vs Offset (AVO) (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.94)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (4 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract This paper describes the selection, design, successful application and performance monitoring of Electrical Submersible Pumps (ESP) in the giant Mangala oil field and Thumbli water field situated in the Barmer basin in Rajasthan, India. Mangala oil field contains in excess of 1 billion barrels of STOIIP (Stock Tank Oil Initially in Place) in high-quality fluvial reservoirs. The field was brought on production in August 2009 and is currently producing at the plateau production rate of 150,000 bopd of which approximately more than one- third of the oil production is from the ESP oil wells. To support the water requirement of Mangala and other satellite oil fields, Thumbli source water field was developed with 5 water production wells with up to 4 wells operating at a time. Each of these water wells is installed with 60,000 bwpd capacity pumps and the field is currently producing up to 225,000 bwpd to meet the water requirements of Mangala and other satellite fields. The Mangala oil field is a multilayer, multi-Darcy reservoir, has waxy viscous crude with in-situ oil viscosity up to 22 cp and wax content in the range of 18 to 26%. The field was developed using hot water flood for pressure maintenance. Significant production challenges included unfavorable mobility ratio with early water cut and hence the early requirement of artificial lift to maintain the plateau production rate. The field has 12 horizontal producers and 92 deviated producers. ESP was selected as the artificial lift method for the high rate horizontal producers while hot water jet pumping was selected as the artificial lift method for low rate deviated oil wells. Each horizontal well is capable of producing up to 15,000 blpd and high rate ESPs were designed and installed to deliver the production requirement. Currently 8 of the 12 horizontal producers are on ESP lift and the remaining four wells are planned for ESP installation in the near future. Apart from two early ESP failures during installation, ESPs have had a good run life; the paper also describes lessons learnt from the infant mortalities. The Thumbli water field, located ~20 km southeast of Mangala field has been developed to meet the water requirement of Mangala and other satellite fields. Thumbli water aquifer is a shallow water field which contains water of ~ 5000 ppm salinity with dissolved CO2, oxygen, chlorides and sulphate reducing bacteria (SRB). 5 high capacity water wells were drilled in Thumbli field to meet the huge water demand from Mangala for water injection in Mangala and satellite field injector wells, hot water circulation in oil production wells and associated water requirement for boilers etc. 1000 HP water well ESPs were designed to produce up to 60,000 bwpd from each well with installed water production capacity of up to 300,000 bwpd from Thumbli field. A state of the art ESP control and monitoring architecture including ESP tornado plotting was developed and successfully implemented in the ICSS to remotely operate, monitor and optimize ESP well performance from the central control room within Mangala field and from the company headquarter located in Gurgaon.
- Geology > Sedimentary Geology > Depositional Environment (0.34)
- Geology > Mineral > Sulfate (0.34)
- Oceania > Australia > Western Australia > Indian Ocean > Perth Basin > Abrolhos Basin > Block WA-325-P > Cliff Head Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.95)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.95)
- (9 more...)
Summary Over the years, environmental legislation has forced changes in the types of scale-inhibitor molecule that can be deployed in certain regions of the world. These regulations have resulted in changes from phosphonate scale inhibitor to polymer-based chemistry, particularly in the Norwegian and UK continental shelf where phosphonates have been either on the substitution list or phased out for many applications. Over the past 10 years, significant improvements in inhibitor properties of the so-called "green" scale inhibitors have been made. However, for one particular operator, the squeeze application of this green scale inhibitor resulted in poorer than expected treatment lifetimes and significant operating cost because of the frequency of retreatment. To overcome the increasing operating cost, an evaluation was made of the current treatment chemicals vs. the older, more-established phosphonate scale inhibitors. The results for the laboratory evaluation suggested that the older chemistry would extend treatment life and reduce operating cost. A case was made to the legislative authority, who approved the use of the phosphonate scale inhibitor, and field applications started. The squeeze lifetimes for the red phosphonate chemistry were shown to be significantly better than the existing yellow/green inhibitors. During the following months, other scale inhibitors with improved environmental characteristics were developed and evaluated. One such molecule was shown to have similar coreflood retention to that of the applied red phosphonate and presented no formation damage. This paper presents the laboratory evaluation of the new scale inhibitor, and illustrates the improvement observed with this new inhibitor through field squeeze-treatment results from a well treated with both the red and new yellow environmental profile inhibitor chemicals. This paper outlines the challenges with environmental legislation and how it has been possible to develop technical solutions (in terms of environmental vs. safety issues and with new inhibitor chemicals) to meet the challenges of offshore scale control.
- Europe > United Kingdom > North Sea (0.51)
- Europe > Norway > North Sea > Central North Sea (0.28)
- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Sleipner Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Skagerrak Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Hugin Formation (0.99)
- (22 more...)
Abstract INPEX has begun construction of one of the world's largest oil and gas projects following the Final Investment Decision (FID) on the US $34 Billion Ichthys LNG Project in Australia on 13 January 2012. The Ichthys LNG Project is a joint venture between INPEX (Operator) and Total with Tokyo Gas, Osaka Gas, Chubu Electric and Toho Gas. The Ichthys Field is situated in the Timor Sea approximately 200 kilometers off the Western Australian coast and over 800 kilometers from Darwin. Three exploratory wells drilled in 2000 and 2001 resulted in the discovery of an extremely promising gas and condensate field with resource estimates from two reservoirs totaling approximately 12TCF of gas and 500 million barrels of condensate. Conceptual studies, FEED and ITT followed and development leading to sanctioning of the Ichthys LNG Project by INPEX and Total. Gas from the Ichthys Gas-Condensate Field in the Browse Basin will undergo preliminary processing offshore to remove water and extract condensate. The gas will then be exported to onshore processing facilities in Darwin via an 889 kilometer subsea Gas Export Pipeline (GEP). Most condensate will be sent to a Floating Production Storage and Offloading (FPSO) vessel for stabilization and storage prior to being shipped to global markets. The Ichthys LNG Project is expected to produce 8.4 million tons of LNG and 1.6 million tons of LPG per annum, along with approximately 100,000 barrels of condensate per day at peak.
- Oceania > Australia > Western Australia > North West Shelf (1.00)
- Asia > Japan > Kantō > Tokyo Metropolis Prefecture > Tokyo (0.24)
- Asia > Japan > Kansai > Osaka Prefecture > Osaka (0.24)
- Oceania > Australia > Western Australia > Western Australia > Timor Sea > Browse Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Timor Sea > Browse Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Browse Basin > Caswell Basin > Ichthys Field (0.99)
- (3 more...)
Abstract The Lower and Middle Ordovician paleocave systems form an important type of reservoirs in the Tarim basin, China. To better understand the impact of fractures on the paleocave reservoir development, with acquired wide azimuth 3D seismic data, both post-stack volumetric geometric attributes and P-wave azimuthal AVO analysis are applied to characterize multiscale fracture distributions. In this study, volumetric seismic attributes including dip, discontinuity and curvature are used to identify sub-seismic faults and associated fracture corridors and to describe subtle folds and flexures within the reservoirs. P-wave azimuthal AVO analysis is applied to detecting high angle fractures. Six azimuth-sectored stacks are used to compute P-wave seismic anisotropy from which fracture density and orientation are estimated. Two major sets of conductive fractures trending northeast and northwest, associated with different tectonic events, are identified using imaging logs from seven wells in the study area. Fractures predicted from geometric attributes and from the P-wave azimuthal AVO analysis are compared. The feasibility of two approaches for characterizing and mapping various types of fractures is investigated. Our results show that geometric attributes can better allow detecting and imaging subseismic faults and fracture corridors. The azimuthal AVO analysis allows detecting zones associated with both large scale fracture corridors and small scale diffuse fractures. However, the poor quality data and local geological structures may prevent from using obtained fracture predictions in a quantitative way. Integrating geometric attributes and azimuthal AVO analysis allows obtaining a comprehensive fracture distribution from fracture networks on the corridor scale to diffuse fracture distributions on the small scale. In this paper, case studies are used to illustrate how these two approaches can be integrated to provide a comprehensive multi-scale fracture distributions calibrated with well data and validated against the conceptual fracture models.
- Asia > China (0.70)
- North America > United States > Texas (0.46)
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin (0.99)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.98)
- North America > United States > Texas > Meramec Formation > Meramec Formation > Mississippi Chat > Mississippi Lime > St. Louis Formation (0.98)
- (23 more...)
Abstract This paper presents the application of an integrated modeling approach to the facility design and construction stages of a mega-project for a giant oilfield offshore Abu Dhabi. The scale of the EPC task is unprecedented in the UAE and requires careful design to optimize the capital investment. In addition, the project uncertainties require that a high degree of flexibility be factored into the design process. The integrated modeling approach couples surface and subsurface flow models to achieve a complete system solution that incorporates many levels of constraints and realistically represents future behavior. This approach addresses a number of key issues. Firstly, multiple different quality reservoirs produce to a shared surface facility. Consequently, the field is highly sensitive to back pressure variation and so requires a rigorous treatment of well and surface physics. Secondly, the sub-surface uncertainties and sheer size of the investment requires a flexible approach to design, hence, many simulation scenarios are required to provide improved decision support. Finally, close collaboration is required between the sub-surface and surface teams to ensure optimization of facilities design and reservoir management for cost and recovery. The adopted methodology utilizes an integration framework which couples reservoir and topsides models into a predictive tool for development planning. This paper describes how the integrated modeling approach was utilized to provide input to design process for several aspects of the field development plan during the design and construction stages. This will include discussion of the phasing of the production facilities, requirement for temporary facilities, modular compression and separation units and the optimization of the drilling program for planned infill wells. The paper presents a best integrated modeling practice supporting facility design process which is applicable for similar scale projects, highlighting the role of integrated model as a means to foster collaboration between surface and sub-surface teams.
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.97)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.93)
A Diagenetic Diagram as a Tool for Systematic Detailed Characterization of Carbonate Rocks: Applications to the Diagenetic Evolution of Hydrocarbon Reservoirs
Inês, Nuno (Partex Oil and Gas) | Azerêdo, Ana (Universidade Lisboa, Faculdade, Ciências, Departamento and Centro de Geologia, Lisboa, Portugal) | Bizarro, Paulo (Partex Oil and Gas) | Ribeiro, Teresa (Partex Oil and Gas) | Nagah, Adnan (The Petroleum Institute, Abu Dhabi)
Abstract Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability. A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core. Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments. This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes. The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
- North America > United States (0.93)
- Asia (0.89)
- Europe > Portugal (0.88)
- Phanerozoic > Mesozoic > Jurassic (1.00)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous (0.34)
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Oceania > Australia > Western Australia > Canning Basin (0.99)
- Europe > Portugal > Lusitanian Basin (0.99)
- Europe > Germany > Valanginian Basin (0.89)