Suijkerbuijk B.M.J.M.,Royal Dutch Shell |
Sorop T.G.,Royal Dutch Shell |
Parker A.R.,Royal Dutch Shell |
Masalmeh S.K.,Royal Dutch Shell |
Proceedings - SPE Symposium on Improved Oil Recovery | Year: 2014
Low Salinity Waterflooding (LSF) is a rapidly emerging IOR/EOR technology that improves oil recovery by lowering the injection water salinity. A membrane-based desalination process provides additional advantages such as reduction of souring,scaling and it can prevent injectivity decline. Proper screening of LSF for a particular field requires performing laboratory SCAL tests to (i) measure relative permeability curves to enable field-scale quantification of the LSF benefits by modeling and (ii) de-risk the potential of formation damage through clay swelling and deflocculation. Salym Petroleum Development (SPD; JV Shell/GazPromNeft) is actively looking into IOR/EOR methods to increase the water flood recovery factor. While ASP is being matured as the main EOR option, several LSF laboratory tests have been performed recently to assess the potential of this technique for West Salym. A key LSF enabler in the area is the presence of large, relatively low-saline aquifers in the vicinity of the field, which can serve as a plentiful source of low salinity (LS) injection brine. This study focuses on the initial Salym LSF SCAL tests performed at reservoir conditions, using representative reservoir core and crude oil, with synthetic brines that reflect the formation and injection water compositions accurately. The experiments comprised a suite of Amott and coreflood tests, following the internal Shell LSF protocol. The tests clearly show a positive LSF effect, with additional oil produced in absence of formation damage. The data indicates that LSF causes a shift in wettability towards a more water-wet behavior, and results in a reduction of Sorw. Upscaling the core flood results to field scale indicated that incremental recoveries within the life time of the field could be 1.7% of oil initially in place (OIIP) in tertiary mode, while a secondary mode LSF scheme would have increased the oil recovery over the same time by almost 4% of OIIP. Copyright 2014,Society of Petroleum Engineers.
Ten T.,Tomsk Polytechnic University |
Panova E.,TomskNIPIneft |
Abramova R.,Tomsk Polytechnic University
IOP Conference Series: Earth and Environmental Science | Year: 2015
Research results of the lithological composition for Upper Jurassic productive sediments in Myldzhino gas condensate field (Tomsk Oblast) have been described. System lithological studies have been based on the layer-by-layer profile description. Recently electrometrical research methods for facies analysis and litho-facial interpretation have been applied. Both lithological and field geophysics data provided problem- solving related to stripping conditions, structure and lithological trap locations. © Published under licence by IOP Publishing Ltd.
Gorbovskaia O.A.,Gazpromneft |
Parnachev S.V.,TomskNIPIneft |
Belozerov B.V.,Gazpromneft |
6th Saint Petersburg International Conference and Exhibition on Geosciences 2014: Investing in the Future | Year: 2014
The article is devoted to investigation of possibilities to optimize routine core laboratory analysis design according to the sedimentological characteristics of reservoir. The work is focused upon permeability measurements. Terrigenous rocks are within the scope of the study. As far as core sampling is concerned, a-priori assessment of necessary number of plugs to be taken is possible on the basis of earlier cored wells for formations deposited in sedimentary environments of which laterally continuous sandbodies are typical, such as, shallow marine alongshore sandbars and barrier islands, or submarine fan system deposits. Moreover, results of minipermeametry measurements may be utilized in order to distinguish socalled "homogeneously heterogeneous" intervals within the reservoir which require different sampling density for permeability characterization. Creation of an individual sub-program for each interval may allow increasing number of measurements within more heterogeneous parts of the reservoir by decreasing them within relatively homogeneous intervals without additional expenses on plug sampling. It is likely to allow more detailed assessment of permeability distribution within the reservoir, and, as a result, make help in reservoir management improvement. Copyright © 2014 by the European Association of Geoscientists & Engineers. All rights reserved.
Goncharov I.,TomskNINPINeft VNK |
Oblasov N.,TomskNIPIneft |
1st Sakhalin Workshop on Far East Hydrocarbons: From Oil and Gas Basin Studies to Field Models 2011 | Year: 2011
Oil and gas formation in Sakhalin Island has been investigated during several decade. But many geochemical questions in updating of regional oil formation model are left in abeyance. A true basin modeling is impossible without their solution. Rock-Eval pyrolysis research included 424 core and cutting samples from wells. Highest oil-generative potential was determined in samples of Pisk Formation. TOC content reaches up to 3.7 %, S2 - up to 39.4 mg HC/g rock in these rocks. Organic matter of Pisk Formation has high Hydrogen Index values (up to 587 mg HC/g rock), which correspond to kerogen type-II. GC/MS analyses of source rock extracts and 16 oil samples from 7 oilfields don't confirm supposition of early-catagenetic formation. Oils have a similar origin. Correlation of the thermal maturity molecular parameter in rock extracts and oils showed that in most investigated rock samples the organic matter has not reached the thermal maturity level of existing oils. The most near-maturity value for oils was discovered in rock samples of Pilsk Formation (Vostochnyy Kaygan No 2 well, depth is 3.3-3.6 km). This can indicate that the oil window zone is located at a depth of more than 3.5 km.
Babov V.N.,TomskNIPIneft |
Geomodel 2012 - 14th Scientific-Practical Conference on the Problems of Integrated Interpretation of Geological and Geophysical Data During Geological Modeling of Hydrocarbons' Deposits | Year: 2012
The resume of theses. Methodological instructions are lied in the basis of algorithm. The algorithm is based on different influence of lithology on TNNL,GGL,AL.methods and let to divide carbonate rocks to limestones, dolomites and dolomitzed limestones and to point reservoir properties of the rocks. The main distinction of this method is that from rhe beginging you should point the lithological identity of the rocks and after this you should do the calculation of porosity and also the refuse of introduction of amendments for clay content.This is achived by using of main parameters, calculated for real composition of the rocks (mixture of limestone -dolomite).