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Collaborating Authors
When classifying the process of oil dehydration for preliminary assessments of the technological parameters of its treatment at various stages of the design and development of oil fields, it is necessary to take into account regional differences, starting with the geographical and geological location of oil deposits and the conditions of their occurrence, ending with the features of the physicochemical properties of reservoir fluids extracted to the surface. On the example of a number of fields in the Samara region, the dependence of the change in viscosity when changing from reservoir conditions to surface conditions is built, a comparative grouping of oil by viscosity in reservoir and surface conditions is considered, consistent with the classification of oil to assess the parameters of its preparation simultaneously in terms of density and viscosity in surface conditions. A conditional comparison of the classification parameters and the required temperature of the emulsion during oil dehydration to a residual water content of 10 wt% (preliminary dehydration) and 0.5-1 wt% (deep dehydration) was carried out according to various literature sources. It is proposed for the range of Paleozoic production of oil wells in the Volga-Ural oil and gas province, in addition to assessing the generally accepted characteristics of oil density and the content of paraffin in it, to select technological parameters for oil treatment, additionally use the relative indicators, taking into account the unique properties of highly mineralized reservoir waters and the heterogeneous hydrocarbon composition of the oil itself. On the basis of the introduced characteristics, the classification of oil dehydration of a number of fields in the Orenburg, Samara regions and Siberia is considered. A comparative assessment of the quality of wastewater treatment was carried out taking into account two calculation methods based on the properties of the separated phases, taking into account the mentioned characteristics, as well as the oil density and the specific load on the interface of the apparatuses for the combined preparation of oil and water.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.48)
- Europe > Russia > Volga Federal District > Samara Oblast > Volga Urals Basin > Zhigulev-Orenburg Arch > Dmitriyevskoye Field (0.97)
- Europe > Russia > Volga Federal District > Orenburg Oblast > Precaspian Basin > Orenburg Field (0.97)
Analysis of strontium sulfate effect on mixing formation water with water from well killing stations at the fields of Samaraneftegas JSC (Russian)
Ostankov, N. A. (Samarsneftegas JSC) | Kozlov, S. A. (Samarsneftegas JSC) | Kuleshov, S. P. (United Research and Development Centre LLC) | Rtishchev, A. V. (Samarsneftegas JSC) | Frolov, D. A. (Samarsneftegas JSC)
The PDF file of this paper is in Russian. At present the majority of oil production companies clearly face the problems with field equipment failure risks through the salt depositions. These problems are allocated to various geological structures while developing the productive reservoirs as well as to physical and chemical properties of produced fluids. The associated water produced jointly with oil is the main source of salt deposition. This water is also used as well killing fluid during geo-physical well survey operations; it is also used during well routine servicing and work-over jobs. The process of salt deposition is mainly referred to drastic water over-saturation with hard-to-dissolve salts due to the reason of non-consistency in physical / chemical parameters of oil production system that is related to the changes of salt-organizing ions in their temperature, pressure and concentration. The chemical composition of inorganic sediments is mainly presented by sulfates and calcium carbonates (anhydrites, gypsum, calcite), barium sulfates (barites) and strontium sulfates (celestite), oxides, carbonates and iron sulfides. In order to evaluate the risks of salt depositions Samaraneftegas jointly with SamaraNIPIneft have conducted scientific research program where they have studied 10-component formation and well-site water composition at well-killing fluid storage facility at the operating fields of the Company, including the quantitative composition of sedimentation ions (cations of Ca2+; Mg2+; Ba2+; Sr2+; Fegen; Na++K+; anions of SO42-; CO32-; HCO3-; Cl-). Within the frames of these works they have defined the water tendency to salt shows and have conducted physical and mathematical simulation of water compatibility. In course of simulation studied it was found that while mixing water from productive formations with well-killing fluids from storage facilities the strontium sulfate may severely affect the operation of both bottom-hole and surface process equipment and pipelines being one of the salt-generating components.
Determination of the chemical composition of formation and sea waters, inorganic deposits sampled at oilfield platform MOLIQPAK (Russian)
Polyakova, N. V. (Institute of Chemistry Far Eastern Branch of RAS, RF, Vladivostok) | Zadorozhny, P. A. (Institute of Chemistry Far Eastern Branch of RAS, RF, Vladivostok) | Trukhin, I. S. (Institute of Chemistry Far Eastern Branch of RAS, RF, Vladivostok) | Sukhoverkhov, S. V. (Institute of Chemistry Far Eastern Branch of RAS, RF, Vladivostok) | Markin, A. N. (Institute of Chemistry Far Eastern Branch of RAS, RF, Vladivostok) | Avramenko, V. A. (Institute of Chemistry Far Eastern Branch of RAS, RF, Vladivostok) | Brikov, A. V. (Branch Sakhalin Energy Investment Company Ltd. in Yuzhno-Sakhalinsk, RF, Yuzhno-Sakhalinsk)
The PDF file of this paper is in Russian. Important criterion for correct selection of scale inhibition protection and methods for treatment of oil equipment is chemical composition of formation water and mineral deposits. The aim of this paper was to study a composition of produced and sea waters as well as deposits drawn from various technological points of the oil-producing equipment. The samples were taken from platform MOLIQPAK of the Astokhskoye area of Piltun-Astokhskoye oilfield located on the northeast part of shelf of Sakhalin Island. Samples were analyzed with various physical and chemical methods including IC HPLC, GLC and X-ray fluorescence spectrometry. Produced waters of the studied oilfield have typical composition for oilfield waters. Total mineralization of studied water samples was 28 g/l in average Major dissolved components of the salt matrix are sodium and potassium chlorides. Concentration of sulfate-ions for different wells varied within 200–1900 mg/l, alkalinity (as HCO3-) - 450–870 mg/l. Acetic acid was major component among volatile fatty acids. Units of equipment where the concentration of carboxylic acids was highest contained iron sulfide in the sediment. It may indicate to occurrence of sulfate reduction processes. According to Sulin's classification formation waters belong to types: sulfate-sodium, chloride-calcium, hydro carbonate-sodium, to groups - chlorides and hydrocarbonate, to subgroups - calcium and magnesium. Inorganic part of the studied deposits consists of sand, clay, insoluble sulfates and carbonates of alkaline-earth metals, corrosion products of pipes and equipment (compounds of Fe and salts of transition metals - Cr, Mo, Zr, etc.). Comparison of water and deposit composition gives information on deposit formation at different technological parts of oil-producing equipment, allows creating chemical models for studying of mechanisms of formation and removal of salt deposits.
- Asia > Russia > Far Eastern Federal District > Sakhalin Island > Sea of Okhotsk (0.54)
- Asia > Russia > Far Eastern Federal District > Sakhalin Oblast (0.35)
- Asia > Russia > Far Eastern Federal District > Sakhalin Island > Sea of Okhotsk > North Sakhalin Basin > Piltun-Astokhskoye Field (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Mangyshlak-Ustyurt Basin > Uzen Field (0.99)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (0.89)
- Health, Safety, Environment & Sustainability > Environment (0.86)
Special aspects of selection of high-pressure well-killing technology at oilfields of Bashneft-Dobycha LLC (Russian)
Vahrushev, S. A. (BashNIPIneft LLC, RF, Ufa) | Gamolin, O. E. (BashNIPIneft LLC, RF, Ufa) | Belenkova, N. G. (BashNIPIneft LLC, RF, Ufa) | Shaydullin, V. A. (BashNIPIneft LLC, RF, Ufa) | Akhmerov, I. A. (Bashneft-Dobycha LLC, RF, Ufa)
The PDF file of this paper is in Russian. This paper presents the data of salt mud testing for abnormal high pressure oil wells. There were defined basic physical and chemical properties of salt solutions and their compatibility with the brine of oil deposits. It is shown that precipitation occurs in the course of preparation of well-killing fluids using the brine from oil deposits of Bashkortostan. The composition of Scale has been examined by means of X-ray phase analysis. The paper presents the results of precipitation intensity calculation by Oddo – Tomson method, considers the peculiarities of high-pressure well-killing technology selection at the deposits of Bashkortostan and offers solutions for well-killing fluids quality improvement. The key moment for the choice of high pressure oil well-killing technologies on LLC «Bashneft» oilfields is the possibility of using formation water as well-killing fluid. However, there are a number of significant limitations. First of all sedimentation occurs when salt compositions on the chloride calcium basis with reservoir water of the Republic of Bashkortostan oilfields are mixed. According to calculations using the Oddo – Tomson technique, it has been found that the colmatant composition is complex and includes insoluble salts. The method of the X-ray phase found that precipitation can attend soluble salts-chlorides. Secondly taking into account the obtained data on water compatibility, preparation of well-killing fluid with maximum density is possible only with the use of fresh process water. The use of reservoir water for the preparation of heavy oil well-killing fluid is possible in a limited range of their required density. Filtration tests show the negative effect of using heavy well-killing fluids on the reservoir. The obtained relative value of reduction of reservoir permeability is comparable with the effect of well-killing fluid based on calcium chloride.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.54)
- Reservoir Description and Dynamics > Formation Evaluation & Management (0.48)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (0.34)
- Reservoir Description and Dynamics > Reservoir Characterization (0.34)
Organization of control over changes in the content of organochlorine compounds at oil treatment facilities of Samaraneftegas JSC (Russian)
Kozhin, V. N. (SamaraNIPIneft LLC) | Konovalov, V. V. (SamaraNIPIneft LLC) | Pashkevich, K. L. (Samaraneftegas JSC) | Khafizov, V. M. (Samaraneftegas JSC) | Shishkanov, B. A. (Samaraneftegas JSC) | Chernov, A. E. (Samaraneftegas JSC) | Kirillov, A. S. (SamaraNIPIneft LLC) | Bodogovsky, S. V. (SamaraNIPIneft LLC)
An important condition for the successful operation of an oil production enterprise is the provision of a given level of oil production and its preparation in accordance with the current regulations. Among the quality indicators of commercial oil, special attention is required to control the content of volatile organochlorine compounds (OCC) in the fraction boiling up to a temperature of 204 ° C (GOST R 51858-2002), since the technological design of oil treatment facilities does not allow cleaning oil from OCC in case their concentration exceeds over regulated values. This paper presents the experience of organizing control over the change in the concentration of OCC in well products and commercial oils on the example of one of the large field oil treatment facilities of JSC Samaraneftegas. It is shown that the concentration of OCC in commercial oil depends on the content of natural organochlorine compounds, geological and technical measures and the use of oilfield reagents. Information on the background content of natural (native) OCC in well production is presented. The average content of native OCC in oil for the studied objects is 1.1 ppm, among which the presence of high molecular weight chlorine-substituted paraffinic hydrocarbons of linear or weakly branched structure with boiling points above 204 °C is recorded. The results of the field assessment of the impact of some types of geological and technical measures on the dynamics of changes in forestry and chemical treatment are presented. Preliminary results showed that geological and technical measures lead to an increase in the content of OCC in the well production, but not higher than the regulated values. The results of the studies (taking into account the continuation of the accumulation of statistical information) can be the basis for predicting changes in forest chemical treatment facilities for oil treatment facilities (nodal mixing points), determining the most "problematic" areas, adjusting geological and technical measure plans in order to ensure control of the forest chemical treatment plant content and exclude situations leading to an increase in their concentration in commercial oil.