Hydraulic fracturing has been the choice for well stimulation in Russia to enhance production for quite some time now. It was not until recently the treatment design has increased in size and magnitude in order to heed the country's aggressive production enhancement strategy to meet the local and international demand. The focus of this paper is to discuss the technical and operational applicability of Massive Hydraulic Fracturing (MHF) strategy to enhance production in the Russian oil fields. A case history of the first well that was treated with MHF is provided. The well reflects the large majority of Russian oil wells, especially in the Western Siberian region, which have tremendous potential to enhance production via this strategy. The well falls in the low to intermediate permeability category (less than 1 to 50 md), which can often be converted to be excellent high producing wells by effective hydraulic fracturing technology coupled with proper artificial lifting system. A comprehensive technical analysis of the well before and after the treatment is provided. This includes production analysis using decline and/or type curve analysis before and after treatment, formation evaluation, well performance analysis to estimate the incremental gain, and forecasting. The design and operational aspects of the hydraulic fracturing treatment is also discussed. The results were encouraging. The production increased by more than double after the hydraulic fracturing treatment with relatively low water cut to date. The well was able to flow naturally after the treatment for a few months before artificial lift is installed. Introduction Hydraulic fracturing has been an established choice for well stimulation in Russia to enhance production. Recently, the size and magnitude of fracturing treatments have increased in order to keep pace with the country's aggressive production enhancement strategy. In Sibneft, the fracturing treatment size has increased from an average of 22 tons up to more than 80 tons of proppant. The treatment size is increasing steadily from small to medium scale for the last three years, and recently, to the point of massive. The definition of Massive Hydraulic Fracturing (MHF) is rather arbitrary as reported in several published literatures pertaining to the subject.1–8 In general, MHF simply refers to very large treatments, typically an order of magnitude larger than the conventional fracturing procedures. In Russia, MHF is referred to as having a treatment of more than 150 tons of proppant. The main goal of MHF is to expose larger surface area of the low-permeability formation, compared to the conventional procedures, to flow into the wellbore, thereby significantly increase well productivity. This paper discusses the technical applicability, including the operational feasibility of deploying massive fracturing strategy, to aggressively enhance production in the Russian oil fields. The main focus is to demonstrate via case history that MHF can strategically be adopted as one of the techniques to stimulate wells and rapidly enhance production in Russia; especially for the oil fields in the Western Siberian region. A documented case history of one of the first wells treated with MHF in Russia is provided in order to show the applicability of the strategy. Well 1102 from Pad 153 of Vyngayakhinskoe field, BP12 formation, has been selected in this analysis. The well is one good example to reflect the characteristics of large majority of Russian oil wells, which falls in the low to intermediate permeability category of less than one up to 50 md. A comprehensive and systematic well performance analysis using production type curve and analytical transient solution models, before and after the treatment is discussed. This includes discussions of fracture design and issues associated with the workover and optimization operations. Field and Formation Descriptions Vyngayakhinskoe field is located in the Western Siberian region. It is an upper cretaceous undersaturated reservoir, which comprised of three major productive formations, BP11, BP12, and BP16. The main focus of this paper is on the BP12 formation, where production development and enhancement activities have been quite active recently. The map and the regional location of the wells producing from BP12 formation are shown in Figure 1. There is only one injector in the region, which is located 400 m to the north of Well 1102. All other wells in the vicinity are oil producers.
With more than 1.2 million miles of gas pipelines crisscrossing the entire landmass of the United States, there is little doubt that the capital investment on these pipelines is tremendous. Optimal use of these pipelines is a must, both for operational reasons and cost-effectiveness. One of the prevalent problems in these pipelines is condensation. The existence of the condensate, in addition to reducing deliverability, creates several operational problems. Pigging and drips are two of the methods used to alleviate this problem. Since condensates are not uniformly distributed along the pipeline, either of these two solution strategies will be rendered ineffective unless the distribution of condensate in the pipeline is known. During the past several years, a compositional hydrodynamic model has been developed at Penn State University. This couples a phase behavior model with a fundamental multiphase hydrodynamic model. This model has since been tested and validated. Several design strategies and operational options that may be encountered in the field are defined and modelled. The results of these are reported in this paper. The results clearly demonstrate that in spite of the complex nature of this problem, condensation in pipelines can be modelled by using the approach presented here.
Recent years have seen a growing trend towards applying new and advanced technology in the Russian oil and gas business to maximize productivity and enhance assets value. This has led to improved efficiency and greater technical challenges. In large measure, Sibneft owes its predominant position as one of the rapidly growing oil producers in the Russian energy business to its willingness to embrace new technology in order to enhance the value and maximize the productivity of its assets. This paradigm shift has been critical to the company, not only to maintain its leadership among the majors in Russia, but also to be consistent with the country's aggressive strategy to enhance production rapidly to meet local and international energy demand. This paper focuses on how Sibneft management has been keeping abreast of new technology in order to meet these technical challenges. Romanovskoe oilfield, which is located in the Western Siberian region, is one such field that has been subjected to this proactive philosophy. Due to the heterogeneous characteristics of the reservoir, inefficient thin beds and relative low permeability, specific applications or "right sizing" of technology are crucial to ensure effective exploitation of the field potential. All the wells in the field are either producing via horizontal wells or have been fracture-stimulated since the beginning of their production history. The critical success factors that emerged from the applications are accurate well placement within the thin oil column (landing the well in the right place and at the right angle), avoiding poor quality reservoir and undulating wellbore for the horizontal wells, and fracture-stimulating the wells in the low productivity regions. The adoption of the strategy has seen substantial increase in the field total production, which is otherwise difficult to achieve without appropriate applications of specific technology. The successes on overall enhance the long-term value of the asset. Introduction For the past several years, there has been a growing trend towards applying new and advanced technology in the Russian oil and gas industry. The main reason for this growing trend has been the increasing awareness of the Russian energy business about the critical need to improve production efficiency and maximize reservoir productivity. This is further catalyzed by the country's aggressive strategy to enhance production to meet the local and international energy demand. Among the major operators in the country, Sibneft has been the frontrunner in embracing this paradigm shift, and has been instrumental in proactively putting the idea into action. The purpose of this paper is not to discuss the philosophy and vision adopted by Sibneft concerning the application of new and advanced technology in detail, but rather to focus on how the company has been adopting and applying certain technologies, namely hydraulic fracturing and horizontal wells, and judiciously utilizing them in order to develop its assets. The underlying philosophy is fundamentally simple, but practical; selecting "fit-for-purpose" solutions, and then "right-sizing" them according to the needs, depending on the nature and characteristics of the reservoirs. The Romanovskoe field, which is located in the Western Siberian region, has been selected as a case example to show the company's experience in leveraging these technologies. The field is one good example to reflect the characteristics of many assets in the Western Siberian region, inefficient thin beds with relatively low permeability, and widespread structural and geological heterogeneities with underlying water bearing zone in close proximity. Due to these heterogeneous characteristics, efficient development of the field to enhance productivity and maximize recovery is a challenge that requires careful selection and application of technology. The paper begins with a fundamental review of the Romanovskoe oilfield structure and geology. This provides understanding of the reservoir and formation heterogeneity, and some critical insights of the technical challenges associated with the development of the field. The key technology applications focus on hydraulic fracturing (for the vertical wells) and horizontal wells. Several well case histories are provided to demonstrate the applicability of the technology employed, including the analysis of the wells and the field production performance to evaluate the overall success of the endeavors in enhancing the value of the asset.
With more than 1.2 million miles of gas pipelines crisscrossing the entire landmass of the United States, there is little doubt that the capital investment on these pipelines is tremendous. Optimal use of these pipelines is a must, both for operational reasons and cost-effectiveness. One of the prevalent problems in these pipelines is condensation. The existence of the condensate, in addition to reducing deliverability, creates several operational problems. Pigging and drips are two of the methods used to alleviate this problem. Since condensates are not uniformly distributed along the pipeline, either of these two solution strategies will be rendered ineffective unless the distribution of condensate in the pipeline is known. During the past several years, a compositional hydrodynamic model has been developed at Penn State University. This couples a phase behavior model with a fundamental multiphase hydrodynamic model. This model has since been tested and validated. Several design strategies and operational options that may be encountered in the field are defined and modelled. The results of these are reported in this paper. The results clearly demonstrate that in spite of the complex nature of this problem, condensation in pipelines can be modelled by using the approach presented here.
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