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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.
The Mackenzie Delta in Canada's Northwest Territories hosts manypermafrost-related gas hydrate accumulations that were indirectly discovered orinferred from conventional hydrocarbon exploration programs. In particular, gashydrate intervals characterized with high saturation show high resistivity andhigh P- and S-wave velocity on well-log data, and are typically found insand-rich horizons. As demonstrated at the Mallik site, the velocity contrastbetween highly saturated gas hydrate-bearing sediments and unconsolidatedwater-bearing sediments is significant and allows their detection with seismicdata. Here, we use 2D and 3D seismic reflection data acquired by industry onRichards Island to map and characterize gas hydrate accumulations beneath athick permafrost area of the Mackenzie Delta. Specifically, we show new seismicevidences of gas hydrate accumulations near YaYa, Ivik and Umiak. The presenceof gas hydrate was previously inferred from well-log data in several boreholeslocated in those areas. All seismic data were re-processed following anAVO-friendly flow that preserved relative amplitude relationships. On suchdata, the strong acoustic impedance of gas hydrate produces strong amplitudeseismic reflections. The seismic signature of gas hydrates is confirmed byseismic-to-well correlation in areas where boreholes are available. Resultsindicate that gas hydrate accumulations occur in structurally-controlled playstypical of conventional oil and gas traps found in this area, and furtherdemonstrate that gas hydrates are part of the regional petroleum system.
The oil production wells and a water source well at Situche Central field will require artificial lift as planned with the subsurface basis of design. Artificial lift for the oil producers is required to maximize ultimate recovery and maintain oil production with increasing water cut. The main goal for Situche Artificial Lift is to provide a lift system that is efficient, the least complicated and robust enough to survive Situche downhole conditions for a minimum 2 ½ years. Such a lift system would be safer (less rig time for pump repairs and less equipment handling and transport) and have the least impact on the environment. Situche Central is a seven well development expected to be sanctioned in Q1 2013, with first oil in 2015. The successful development of Situche Central requires the re-completion of the two existing exploration wells and the drilling of two additional oil producers and water handling wells. This is the Phase 1 development.
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.
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.
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.
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.
Abstract Shale formations have laminated structures that result in directionally dependent mechanical properties. Conventional completion design approaches do not consider the material anisotropy or the laminated nature of shales. This can result in an underestimation of stresses, and lead to incorrect conclusions about the lateral landing points and the perforation intervals. In this paper, the authors demonstrate the importance of considering the anisotropy in the completion design using a case study from the Horn River Basin (HRB), the largest shale gas play in Canada. Shale formations in the HRB are strongly anisotropic with horizontal to vertical Young's modulus ratios varying from 1.2 to 3.5. Field data from the HRB is examined to evaluate the impact of mechanical anisotropy on break down pressure, fracture initiation and fracture containment. Numerical simulation of the completion design was conducted using a planar 3D fracture model. Results of the numerical simulation indicate that the mechanical anisotropy greatly influences the minimum horizontal stress which in turn impacts the fracture containment and fracture geometry. Strong mechanical anisotropy results in lower fracture initiation pressures and lower tortuosity at the wellbore face. Consequently, selecting the landing point in sections with high anisotropy will minimize the fracture initiation problems. The authors conclude that the heterogeneous and anisotropic nature of shales needs to be properly characterized and taken into account when making decisions on lateral landing points and completion design.