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Malshakov, A. V. (Tyumen Petroleum Research Center) | Oshnyakov, I. O. (Tyumen Petroleum Research Center) | Zhadaeva, E. A. (ITERA) | Weinheber, P.. (Schlumberger) | Ezersky, D. M. (Schlumberger) | Filimonov, A. Y. (Schlumberger) | Novikov, S. V. (Schlumberger)
Abstract Commercial production from the thinly-laminated Turonian deposits of North West Siberia has been proven in many wells. But despite the fact that we see these layers in many fields and they are in fact the primary development target, the reservoir properties are not well studied and thus their ultimate potential is unclear. To date, the obstacle has been the sand shale laminations that we encounter are on the order of a few millimeters to even fractions of a millimeter thick. Standard log interpretation method have proven to be inadequate, including the application of the latest deconvolution techniques of using a high resolution measurement such as a microimager to inform the layering of standard resolution devices. Even core analysis is ambiguous due to the heterogeneous and anisotropic nature of the reservoirs. In this paper we discuss a complete method of analyzing these thinly-laminated layers with a view to resolving a fuller petrophysical understanding.
Zagrebelnyy, E. V. (JSC Messoyakhaneftegaz) | Glushcenko, N. A. (JSC Messoyakhaneftegaz) | Martynov, M. E. (JSC Messoyakhaneftegaz) | Tsiklakov, A. M. (Schlumberger) | Blinov, V. A. (Schlumberger) | Weinheber, P.. (Schlumberger) | Karpekin, Y. A. (Schlumberger) | Ezersky, D. M. (Schlumberger) | Bugakova, Y. S. (Schlumberger)
Abstract Field development planning requires a proper understanding of layer permeability in order to predict production rates. Experience with horizontal production wells in the Pokurskaya formation of the Messoyakhskoye field showed systematically lower flow rates from the B sands versus the C layers even though their petrophysical properties appear similar. It was proposed that differing permeability anisotropy between the layers might be the cause and an upcoming well in the field offered the ability to test this hypothesis. A logging program that included Vertical Interference Tests (VIT) with a Wireline Formation Tester tool (WFT) and advanced petrophysical logs, 3D resistivity, NMR and dielectric scanner was run to estimate the the kv/kh ratio pointwise with VIT and extrapolate these measurements through the entire section. VIT tests were done at several depths with a dual-packer for the fluid withdrawing and a pressure probe for pressure monitoring. Estimated anisotropy coefficient varies mainly from 0.02 to 0.07 but with both higher and significantly lower values at some depths, which indicate extremely limited connectivity in some intervals. In general, the kv/kh ratio is significantly lower in the upper interval of the PK1-3 formation versus its lower interval. The triaxial induction logging shown the anisotropy of the reservoir electrical properties (Rv> Rh), caused by thin interbedding of the sandy fraction rocks with the interlayers of clays and siltstones, which are several times lower than the resolution of standard logging methods. Similarly, interlayering of thin sand and silty rock types, which have different absolute permeabilities, causes anisotropy of the formation permeability. It is possible to estimate the permeability of the macroanisotropic formation along and across the bedding knowing the water-retaining capacity as well as the laminated sand fraction coefficient. The VIT and the logging results are consistent enough. The VIT test results are the reference measurements while the 3D induction logging results are used for interpolation and extrapolation of these direct measurements through the entire interval and in wells without VIT tests including horizontal wells. The subsequent analysis showed a significant anisotropy of permeability in the Pokurskaya formation, which varies along the interval of the formation and, probably, laterally. This must be taken into account when calculating the flow rates of the well. The complex of studies makes it possible to perform an express estimation of the permeability anisotropy in the pilot wells in order to select the optimal interval for horizontal wells landing.
Filimonov, Anton (Schlumberger) | Ezersky, Dmitry (Schlumberger) | Shray, Frank (Schlumberger) | Martynov, Mikhail (RN-Nyaganneftegaz) | Khabarov, Aleksey (RN-TPRC) | Shkunov, Evgeny (LLC Novatek Scientific and Technical Center) | Baybikov, Chingiz (CJSC )
Future energy for Russia will come from additional investment justified by an increased valuation of reserves. Western Siberia is well known for its abundance of laminated, siliciclastic reservoirs. Due to technical limitations of the past, the value of the oil or gas reserves within such reservoirs has been difficult to quantify and typically undervalued. Laminated, hydrocarbon-bearing reservoirs are electrically anisotropic; evaluating them with conventional resistivity tools and computational methods commonly provide pessimistic results. A new generation of wireline tools and analytical methods were purposely developed to provide accurate valuation of reserves within such reservoirs. Triaxial induction measurements of horizontal and vertical resistivity, as well as formation dip and azimuth, are used to determine the true resistivity of the oil-bearing sand laminations. Integrated, high-resolution bulk density and neutron porosity measurements quantify total formation porosity as well as the porosity of the important sand laminations. Magnetic resonance measurements provide essential information on the fluid properties and rock quality. The comprehensive volumetric analysis for the laminated formation provides an accurate reservoir summation for reserves valuation. As our field examples demonstrate, the oil company and Russia have added significant value to their oil reserves that may otherwise have been underestimated, undervalued, or bypassed.
Western Siberia represents the heart of the oil industry of Russia. Approximately two-thirds of Russia’s oil production comes from fields in Western Siberia. While this region is mature, West Siberian production potential is still significant, but will depend on improving the economics of production at fields which are more complex than once thought. Complexity stems, in part, from laminated formations which are ubiquitous in the region.
Some of the well-known, laminated formations there include the Vikulovskaya, Achimovskaya, Tyumenskaya, and other Cretaceous and Jurassic intervals. We shall illustrate the application of new technology that addresses – and likely improves - the issue of reserves valuation within laminated formations in Western Siberia. We believe that the volume of oil and gas in these formations has been generally underestimated. This results in the underestimation of the asset value of the oil company; and this affects every economic decision within the company from the top down.
The new technology is composed of two parts. The first part is hardware: a triaxial induction logging tool. The second part includes a fresh, new analytical approach to thinking about laminated formations coupled with a modern log analysis computational workflow. All of this new technology, hardware and software, has been applied in Western Siberia with good results for the Russian oil companies.
Nguyen Pham, Kim Thien (Schlumberger) | Doan, Dung Thi My (Schlumberger) | Nguyen, The Dac (Schlumberger) | Lee, Samie (Schlumberger) | Nguyen, Luc Quoc (Schlumberger) | Ngo, Hai Huu (Bien Dong Petroleum Operating Company) | Ngo, Quan Anh (Bien Dong Petroleum Operating Company) | Khuc, Giang Hong (Bien Dong Petroleum Operating Company) | Tran, Hung Ngoc The (Bien Dong Petroleum Operating Company)
Thin beds are capable of yielding a reasonable amount of hydrocarbon if discovered and evaluated. However, most thin beds are bypassed due to the low vertical resolution of conventional logging tools, which results in significant underestimation of hydrocarbon in the sedimentary unit. To better characterize thin beds and maximize reservoir potential in the thinly bedded reservoirs, a novel methodology has been developed that integrates resistivity images and core data with standard logs.
First, lamination and thin-bed intervals were identified with the help of borehole images and mud logs. Also, high-resolution shallow resistivity from the images was used to output a set of high-resolution logs with a log resolution enhancement technique. This set represents the true layer property and was applied in petrophysical analysis incorporating core study to yield accurate estimations of porosity, water saturation, and permeability. A saturation height function was built from special core analysis (SCAL) to provide an independent saturation estimate for calibrating the petrophysical model. The Thomas-Stieber method, a well-known method for detecting and quantifying laminated sand-shale, was also referenced.
This methodology was applied in the evaluation of five gas wells producing from the same formation. The key well with images, core, and electric logs was used to build the petrophysical and saturation height models. The results show good agreement in estimation of water saturation between independent techniques in the key well and hence demonstrate the value of this technique. The model was propagated to other wells in the same field, and this again showed the validity of the methodology with good agreement in the result between different techniques. The success of the study demonstrates how an integrated thin-bed evaluation model can provide a more definitive representation of thinly bedded sands in terms of their volumes in net sand, sand porosity, and hydrocarbon in place. The methodology yielded considerable improved estimation of hydrocarbons in place compared to the evaluation using only standard resolution measurements. In the thin-bed intervals in the target reservoir, the net thickness increases more than 50% in comparison to the estimation with standard logs.
The improvement in formation evaluation in thin-bed reservoirs resulting from this methodology provides a comprehensive picture of the field reserve that not only helps in the new production plan as input into static and dynamic reservoir models but also leads to effective strategies in field development and management.
Martinov, M E (TNK-Nyagan) | Kozlov, A V (TNK-Nyagan) | Platunov, A A (TNK-Nyagan) | Filimonov, A Y (Schlumberger) | Ezersky, D M (Schlumberger) | Egorov, S S (Schlumberger) | Charupa, M V (Schlumberger) | Tsiklakov, A M (Schlumberger) | Mikhalteva, I V (Schlumberger) | Weinheber, P (Schlumberger)
Abstract In a recent Em-Egovskoe well an extended logging suite was performed with the aim to evaluate the petrophysical properties of Jurassic and Paleozoic formations as well as to improve the structural geological model of this part of the oilfield and to do detailed characterization of the dynamic model by desired properties of formations and fluids. Apart from a standard "triple combo" logging suite the following advanced technologies were applied in the well: neutron-gamma spectroscopy, nuclear magnetic resonance, formation micro imager, formation testers in different modes of reservoir and fluid properties evaluation. Noteworthy, the zone of interest was considered to contain only oil-saturated reservoirs – no gas cap was expected. Indeed on the initial triple combo log data there were no routine gas attributes were observed. Gas-saturated reservoirs were only observed based on integrated analysis of standard and advanced log data, particularly, nuclear magnetic resonance and cross-dipole sonic measurements. Gas-saturated intervals were fully proven by formation tester using downhole fluid analysis (DFA) As a result, one of the Jurassic layers was acknowledged as gas/gas-condensate saturated down to the bottom and the rest of Jurassic intervals were found to be oil saturated. The Abalak formation was also encountered in this well and evaluated. Thin carbonate streaks were identified with the micro-imager and were tested with the dual-packer module of the wireline formation tester. The result was the first ever Abalak oil sample in this field. Furthermore, based on pressure transient analysis of the build-up from the pressure test it was suggested that these tight streaks are laterally discontinuous. Finally, we created a stress profile in the Jurassic and Paleozoic layers. Based on formation micro-imager and acoustic scanning measurements the maximum horizontal stress directions and magnitudes were estimated. Then dual-packer formation tester micro-stress measurements were made to acquire direct measurements of fracture closure pressure. These measurements were used to calibrate our stress model.