Each year, the market offers new technologies and approaches, which, provided they are properly introduced, can make a positive contribution to business development of oil companies in depleting brownfields and greenfields with complicated conditions. Production increments supported with conventional technologies have been on decline from year to year.
This work offers approaches to managing the process of searching, introducing, and monitoring optimum technologies providing for economically feasible access to reserves, oil recovery enhancement, and cost reduction, which can be used by oil and gas companies to improve their performance.
In view of current and future field problems, the following technological priorities have been defined: oil recovery enhancement techniques, effective drilling, seismic surveys, water flooding, etc.
Key instruments of technology strategy implementation include methodology, process regulations, and information systems for assessing efficiency of decisions taken.
In order to develop the innovational culture, it would be desirable to hold regularly regional and corporate Technology Forums, develop knowledge bases that would ensure exchange of experience and development of personnel competencies.
To evaluate pilot project results, information systems should be introduced, which would provide for monthly monitoring of pilot project performance evaluation criteria.
If a technology is successfully tested in the course of the pilot project, broad-scale scaling-up of this technology is started. It implies updating the technology scaling-up potential, general forecast of economic results, and scaling-up program monitoring during the year.
Risk mitigation and success of the new technologies program depend on managing the initiation, monitoring, and personnel motivation process.
Introduction of proposed methodologies, processes, criteria, and information systems for prompt evaluation of pilot project results during wellwork operations helps take timely and high-quality management decisions in the course of implementing the new technologies program, which is important for companies holding a balanced portfolio of oil brownfields and greenfields, gas fields, and fields with unconventional hydrocarbon reserves.
Joint Russian-Vietnamese Company "Rusvietpetro" was established in 2008 to develop oil fields in Russia, the founders of the Company are "Zarubezhneft" PC and "Petrovietnam" OGC.
The operating area is located on the north-eastern section of Bolshezemelskaya tundra (eastern part of the Pechorskaya lowland), which is a hilly plain, cut by a dense river network, with numerous morainal hills and ridges. Natural zone - sub-arctic tundra. The area is virtually unpopulated.
Being aware of its responsibility to preserve a favorable environment and rationally manage natural resources, Management of the Company regularly and systematically fulfills all the requirements of licensing agreements. Significant amounts of funding for environmental programs are considered by the company to be great investments in the future and the guarantee of the environment quality of the regions in which it operates.
Environmental policy of JC "Rusvietpetro?? LLC is based on laws and legal acts of the Russian Federation, its subjects, takes into account the basic provisions of international conventions and agreements aimed at the harmonious production development.
The company has developed and implemented a system of monitoring of environment and condition of the subsoil of licensed areas "CKU (Central Khoreyver Uplift) blocks ? ? 1-4" on the basis of geo information system (hereinafter - GIS) which helps to estimate the impact of the undertaken work on the environment, to control the nature and intensity of ecological processes, generate and distribute information on dangerous ecological processes to ensure the fast decision making for environmental protection, organization of the measures to prevent and eliminate oil spills on the Company's territory.
Tsiklakov, Alexander (Schlumberger) | Weinheber, Peter John (Schlumberger) | Wichers, Wicher Roelf (Schlumberger) | Zuo, J. (Schlumberger) | Zimin, Sergey (VankorNeft) | Driller, Anna (VankorNeft) | Oshmarin, Roman Andreevich (VankorNeft)
Many techniques are used in industry to determine reservoir hydraulic connectivity from static data. These can be rock-based techniques such as seismic mapping, well to well correlations and geological modeling. Or they can be fluid based techniques such as pressure and fluid gradients. Fluid pressure gradients acquired with formation testers have long been popular but they are understood to be able to identify a lack of connectivity and cannot necessarily prove the presence of connectivity.
Recent work has shown that mapping fluid gradients can be much more definitive. For light fluids this mapping is based on the gas-oil ratio (GOR). For heavier fluids, with little GOR variation, this technique requires mapping a different parameter. It has been suspected that asphaltene content was the parameter to map, but until recently the science of asphaltene prediction was unclear. Recent advances in asphaltene science have now clarified the mechanism for asphaltene distribution in the reservoir and gradient prediction is now possible. And most fortunately it turns out that the asphaltene gradient is relatively easy to measure in-situ.
In this paper we present the science behind asphaltene gradient prediction and show how fluid gradients are a superior way to infer reservoir connectivity. We then present data from an Eastern Siberia oilfield where asphaltene gradients are determined in-situ with a wireline formation tester. These gradients are verified by later comparison to laboratory measurements. Finally and most importantly, we show also how the asphaltene content is used to predict reservoir connectivity both vertically and laterally.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-162065-MS.
The project presents the results of the production logging campaign performed in horizontal wells of the Korchagina oil gas-condensate field. FSI-MaxTrac tool was run for inflow profiling purposes. Obtained results allowed to:
• Assess the multiphase fluid dynamics along the wellbore
• Identify the oil, gas and water inflow zones
• Analyze the presence of cross-flow behind casing and assess the swelling packers integrity
• Perform the completion effectiveness and horizontal drain productivity analysis.
This was the first time in this field when production logging was performed. Comprehensive analysis of OH logs and FSI data helped to better understand the reservoir nature and determine the source of gas.
Production data obtained with FSI technology allowed the client to optimize well flowing regimes; to determine the main directions for future downhole operations, workover procedures and bottomhole zone treatment in order to reduce the inflow of free gas.
Kozhevnikov, Dmitry (Gubkin Russian State University of Oil and Gas) | Kovalenko, Kazimir (Gubkin Russian State University of Oil and Gas) | Deshenenkov, Ivan Sergeevich (Gubkin Russian State University of Oil and Gas)
The integration of petrophysical and seismic data is a key technology for reservoir characterization and subsurface fluids monitoring. Rock physics as a link between seismic and logging data, it's applied to predict reservoir parameters, such as lithologies and pore fluids, from seismically derived attributes. Fluid substitution procedure is the rock physics technique for understanding how seismic velocity and impedance depend on pore fluids. The conventional fluid substitution model (Gassmann's model, 1951) assumes homogeneous water saturation without dividing on free and residual water shares.
On the base of petrophysical model of effective porosity we establish a new way of Gassmann's relation application for fluid effect on elastic properties simulation. This fluid substitution model takes into account free and residual water volumes and properties separately and cement swelling as well. Developed model was applied for Western Siberia sandstones and Eastern Siberia carbonates investigations. Seismic responses on oil and gas reservoirs characteristics were modeled with presented approach. Reservoir parameters such as saturation type, residual water features, reservoir properties were studied in seismic field with AVO modeling and simultaneous inversion of synthetic seismograms. The determination of conventional and developed model accuracy characteristics is carried out with Monte-Carlo technique. The outcomes indicate that the estimated error of proposed model is in 1.3-1.5 times less than conventional one.
The results of stated work could be the petrophysical base of the technique for reservoir saturation type prediction from seismic data, which provides identification of pay-zones, reservoir saturation mapping and three-dimensional modeling in order to drill for oil and gas.
Poedjono, Benny (Schlumberger) | Rawlins, Sheldon Andre (Schlumberger) | Singam, Chandrasekhar Kirthi (Schlumberger) | Van Den Tweel, Alexander (Schlumberger) | Dubinsky, Alexey (Schlumberger) | Rakhmangulov, Rustam (Schlumberger) | Maus, Stefan (Magnetic Variation Services)
Drilling in Russia's Far East has always been associated with industry-defining ultra-extended-reach drilling. With the emergence of more powerful drilling rigs and advances in measurement- and logging-while-drilling (MWD and LWD) tools, these wellbores can be designed to reach farther. Therefore, accurately penetrating and exploiting distant reservoirs have resulted in critical dependence on high-accuracy surveying techniques. Successful target penetration and meeting anticollision requirements without the need for shutting production in nearby wells are key proponents for a geomagnetic referencing service (GRS). Geomagnetic referencing is the technique to minimize the lateral position uncertainties when using MWD. This is particularly important for wellbores that extend the boundary of the drilling envelope with stepouts greater than 13 km. The wellbore azimuth accuracy is highly dependent on the quality of the magnetic data used to produce the geomagnetic reference model. This model characterizes the absolute magnitude and vector direction of the natural magnetic field for every point along the wellbore. Representation of the local crustal magnetic contribution is key to the process since it constitutes a significant error in the lateral wellbore position. Since 2011, a new, highly accurate geomagnetic referencing methodology has been used in Russia's Far East. Global contributions are accounted for by a high-definition geomagnetic model (HDGM). In addition, the local crustal magnetic anomaly is represented by 3D ellipsoidal harmonic functions tracking the shape and depth of the Earth, thereby providing seamless integration with HDGM and avoiding distortions faced by conventional plane-Earth approximations. A comparison with the previous industry standard shows improvements of 0.5° in azimuth determination. This high-degree geomagnetic technique will serve well for a number of upcoming developments in Russia's Far East, continuing to push the drilling envelope and providing essential, accurate wellbore positioning, while offering significant time and cost savings.
Ruksanor, Warakoon (Sakhalin Energy Investment Co. Ltd.) | Webers, J. (Sakhalin Energy Investment Co. Ltd.) | Vargas, E. (Sakhalin Energy Investment Co. Ltd.) | Gdanski, R. (Shell International Exploration and Production) | Vickery, S. (Shell International Exploration and Production)
Well LA-552 is the first Lunskoye horizontal oil rim appraisal/producer well targeting the oil rim underneath the Daghinsky gas reservoir. The well is a smart well completion having three zones (one gas zone for auto gas lift and two oil zones) remotely controlled by three inflow control valves (ICV's).
Pressure transient analysis on production data indicated a very high Darcy skin factor causing much lower production than expected. This was predominantly caused by overbalanced perforating with an oil-wet calcium carbonate (CaCO3) fluid-loss control pill used in the production liner.
Due to the well configuration, the damaged zones were not reliably accessible by wireline or coiled-tubing making re-perforation or acid jetting very difficult and risky. Without well recompletion, the only remaining option was to pump acid down the tubing through the ICV's to dissolve the pill across the long perforation intervals of both oil zones (approx. 200 meters long for each zone).
Zonal coverage (diversion) was expected to be a major challenge for an acid remediation treatment, since the perforations were behind tubing and accessible only through the ICV's. Various diversion methods were considered. Foam diversion in combination with a slow reacting acid system was selected to ensure zonal coverage.
An extensive series of lab tests were performed resulting in an acid blend of 9% formic acid containing 7% KCl (temporary clay stabilizer), 2.5% mutual solvent, 0.6% corrosion inhibitor, 15 lb/Mgal inhibitor aid, and 2% foamer being recommended for removal of damage believed to be oil-wet carbonate filter cake. The recommended acid was qualified as having passed oil-wet carbonate filter-cake dissolution tests, mud and oil compatibility tests, corrosion tests, and foam stability tests.
The acid stimulation was successfully performed in September 2011 with the following result:
Limited success for the lower zone. P.I. increased by 54% but no significant improvement seen in Darcy skin. The limited success of the lower zone could be explained by a combination of low injectivity (0.5 bpm) and operational challenges causing sub-optimum foaming.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-162096-MS.
Carbonate reservoirs which contains significant amount of the remaining oil reserves in the Tatarstan Republic and in Russia are normally always naturally fractured. The presence of natural fractures creates additional heterogeneity of the reservoirs structure and makes an essential impact on the development strategy for such reservoirs. An integration of modern logging methods and special studies of oriented cores can give better characterization of such complex reservoirs.
To estimate naturally fractured reservoirs' characteristics in carbonate deposits of the Tatarstan Republic the network of key wells were drilled with oriented cores recovered. To date ten such wells have been drilled. Core studies for qualitative and quantitative fracture system analysis have been made. Based on these studies main types, morphology and orientation of occurred fractures were identified. The depth, dipping angle, azimuth and distribution function has been determined for each fracture type from oriented core studies. Analysis of full-size core allowed estimating secondary porosity in intervals with caverns present. In the same intervals in addition to standard logging set special open hole logging was done including micro-resistivity and acoustic imagers, ultrasonic logging.
Core measurements and logging data was analyzed in specialized software FracaFlow. Based on this analysis it was shown that core data and log data are in good agreement to each other and can be used in combination for better reservoir description in carbonates. The core orientation technique works best for wells with high inclination while micro-imagers can only be used in low angle wells (less than 40°). Low aperture fractures can be successfully identified on core in thick formations however the core orientation method fails in thin interbedded formations. The enhancement for core orientation technique was suggested which uses formation dipping angle data.
Data received will help to evaluate carbonate reservoirs in more details. It will be taken in account while drilling new wells and for design of oilfields' development.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-162066-MS.
The paper investigates the processes of condensate recovery from low-permeable formations during depletion-driven development of gas-condensate deposits. The studies were based on simulating multi-component flow of various gas-condensate mixtures in reservoirs with a large range of permeabilities. As a result, the key causes of decreased condensate recovery from low-permeable formations compared to "regular?? reservoirs have been established. It was shown that for low-permeable formations, due to large pressure drawdown cones, the additional condensation of ?5+ components because of an "non equilibrium?? effect is possible, where the flowing gas phase is out of equilibrium to the retrograde condensate.
The main technological factors influencing the condensate recovery from low-permeable formations were identified, as well as possible ways to increase condensate recovery.