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Summary The cost-effective development of low-permeability hydrocarbon formations of small thickness requires horizontal wells with multi-stage hydraulic fracturing (MS-Frac). The presence of higher or lower layers that are water-saturated and weak barriers to height growth imposes a restriction on the desirable geometry of the fracture to prevent a breakthrough into a flooded interval. Combining several methods of fracture height restriction and controlling such height can improve the efficiency of multi-stage hydraulic fracturing. The first technology to control the effective pressure was based on changing fracturing fluid rheology and resulted in a decrease in the net pressure and the fracture height. The main treatment buffer utilized a hybrid fluid design. The second technology used to limit the height of the fracture was based on creating artificial barriers inside the fracture that restrict height growth. In this case, a special mixture of proppants was pumped before the primary proppant-laden fracturing main stage. The construction of a horizontal well with a multizone completion implies the possibility of carrying out small volume multistage fracturing to prevent breakthrough into a water-saturated interval, creating an effective drainage zone. For the first time in the given field, MS-Frac was performed using combined technologies and techniques for fracture height growth restriction. The operations demonstrated successful results of horizontal multizone well treatments, where the rheology and fluid rate control methods were used to restrict the fracture geometry growth, and proppant slugs were used to create artificial barriers to arrest the fracture height growth.
This reference is for an abstract only. A full paper was not submitted for this conference. Introduction Kamennoe field is one of the most valuable assets and one of the major development projects of TNKBP in Western Siberia. Most of the production in Kamennoe comes from the shallow VK formation of Neocomian age. Most of the reserves are attributed to the upper VK-1. Typically, the underlying VK-2 formation is water- saturated with a relatively weak barrier toward VK-1. Stimulation Practices Overview in Kamennoe Field, Western Siberia Hydraulic fracturing is being successfully used to uncover the reserves of Kamennoe field and sustain production growth. One of the major challenges is placing the desired volume of proppant into the target formation (VK-1) without breaking into the waterbearing VK-2 through the weak barrier. To address this challenge, the series of techniques has been successfully introduced to assist proppant placement into the target zone while reducing the risk of breakthrough:• artificial barrier placement • linear fracturing fluid at the pad stage (as opposed to conventional X-linked fluid) to reduce the net pressure developed during the fracturing treatment • low-viscosity viscoelastic surfactant fluid treatment. Modeling Approach Until recently, the hydraulic fracturing simulation model was based on a conventional set of logs (GR, SP, NKT, GZ, PZ, etc,) and the gut feeling of the engineer. Over time, we learned that such an approach can lead to an inadequate model that could overpredict the strength of the lower barrier and result in fracture breakthrough to the water zone (current breakthrough rate in the new pads is 32% based on 50% WC cut off, Fig.1). To address this issue, the advanced acoustic logging of VK formation in Kamennoe field was done by running DSI log in one well and waveform sonic logs in six other wells. Formation mechanical properties as established from acoustic logs, have been associated with lithofacies, based on the conventional set of logs and extrapolated throughout the field for further usage in simulation modeling. Fig.1 - Post-frac performance based on the conventional modeling approach approach, the advanced planar 3D hydraulic fracturing simulation was performed for the wells that showed no breakthrough based on conventional model (Fig.2), but that have been put on production with the postfracturing WC>50 % (Table 1). Table 1 - Production parameters of the well that did not show any breakthrough to VK-2 according to the conventional model. Fig.2 - Conventional model for the well 5485 does not show breakthrough to VK-2. Fig.3 - Planar3D model shows breakthrough. The fracture geometry obtained from the planar 3D model has been aligned with the postfracturing production results (Fig. 3). Second, the input for the conventional simulation was adjusted accordingly and the conventional model was put in agreement with the advanced model and postfracturing production results (Fig.4). Fig.4 - Conventional model aligned with the planar 3D simulation, and production results showing breakthrough. Third, the modified input for the conventional simulation is now being used routinely to model new fracturing jobs. Results As a result, the process developed on the basis of this study shows improvement in both geometry prediction accuracy and postfracturing water cut (Fig.5). Fig.5 - Post-frac performance based on the new modeling approach Conclusion Production water cut is one of the most important economic parameters of the Kamennoe field development project because of water lifting/handling cost in the environmentally sensitive area. The current study showed that the risk of breakthrough to waterbearing formations can be reduced by using advanced acoustic logging and fracturing simulation technologies in the high-profile development project. Acknowledgements Authors would like to thank TNK-BP and Schlumberger for permission to publish the paper and for continuous cooperation and knowledge sharing.
Parkhonyuk, Sergey (Schlumberger Oleg Sosenko) | Levanyuk, Olesya (Schlumberger Oleg Sosenko) | Oparin, Maxim (Schlumberger Oleg Sosenko) | Sadykov, Almaz (Schlumberger Oleg Sosenko) | Mullen, Kevin (Schlumberger Oleg Sosenko) | Lungwitz, Bernhard (Schlumberger Oleg Sosenko) | Enkababian, Philippe (Schlumberger Oleg Sosenko) | Mauth, Kevin (Schlumberger Oleg Sosenko) | Alexander, Karpukhin (TNK-BP.)
Abstract Excess water production is a major concern for Russian oil companies. Maturing fields are producing at ever-increasing water cut resulting in problems such as the cost of disposal and environmental issues. In recent years, operators have shown a rising interest in Relative Permeability Modifiers (RPMs) as a potential solution to reduce water production. RPMs are designed to disproportionately reduce the relative permeability to one phase (water) over the oil phase. RPMs are a preventive approach to reduce water production. Ideally, they should completely block water flow without affecting oil flow. While RPMs are used worldwide, they must be adjusted to the reservoir conditions. This becomes even more important in the case of hydraulic fracturing of formations with nearby water-saturated layers. Commonly, service companies recommend one type of RPM which fits all reservoirs. This paper demonstrates how RPM selection on reservoir cores is critical for successful application in the field. We describe laboratory testing and review field trial results of RPMs in a low permeability (2 to 14 mD), highly laminated formation. Because RPMs are typically used only in high-permeability reservoirs, this application is unique. We evaluated chemically different RPMs on actual core material and found strong performance variations of the tested RPMs. We selected a suitable RPM following both core flow testing and compatibility testing. For the field test, wells in the Krasnoleninskoe oilfield were selected for RPM treatments. Oil production was increased in most cases while the water cut was reduced or only slightly increased by up to 5% during 6 months following the treatment. These results show that with proper evaluation, RPMs can also be successfully used in low-permeability reservoirs. We demonstrated also that otherwise proven successful RPMs may not fit every reservoir and proper evaluation and monitoring is critical for success.
Platunov, Andrey (TNK-BP) | Nikolaev, Maxim (TNK-BP) | Leskin, Fedor (TNK-BP) | Kaluder, Zdenko (TNK-BP) | Masalkin, Yuri (TNK-BP) | Davidenko, Igor (TNK-BP) | Fedotov, Vladimir (TNK-BP) | Murzinov, Alexey (Trican Well Services)
Abstract For the first time in horizons of Tumenskoe formations of Em-Egovskoe oilfield in Krasnoleninsky play of Western Siberia to achieve the maximum wellbore contact with heterogeneous multilayered formations the technology of multistage fracturing in horizontal well was used. It was a three staged fracturing job with use of coiled tubing to prepare well in between stages followed by well kick off and production start up. Paper describes the experience of challenges overcoming during the different stages of horizontal well architecture, principles of equipment selection and fracturing design. This particular work was in 2010 and originated the first brief into the time of multifracturing horizontal wells of Tumenskoe formations in Em-Egovskoe field, Western Siberia. Multistage fracturing in horizontally drilled well is one of the effective technological solutions for Tumenskoe formations in Em-Egovskoe field. Remoteness and not yet confident knowledge of pay zones at current stage of described field wittingly made the preconditions for selecting the cost effective well design to suit the productivity of the well. That pilot multistage fracturing project presented itself as practical and reliable method to stimulate the production in horizontal well in Tumenskoe formations of Em-Egovskoe field Krasnoleninsky play. With more experience in further use of this technology will allow keeping this drilling and completion method as economically effective in field of this subject. This paper showed the problems occurred during the well drilling stage those also some affect on the followed completion and fracturing operations. Technological solutions have been offered based on study in this paper for future wells. As result of the analysis and gained experience the recommendations are made to ease the construction of well as for example to use the liner wellbore design. A number of recommendations are made for fracturing and coiled tubing design, preparation, equipment availability and technological processes. Presented work preforms the hot topic of glimmering entry into massive multistage fracturing in formations of Bazhen-Abalak and Tumenskoe horizons in Western Siberia. The specifics of drilling and completion in horizontal wells are brought out based on described in paper geological conditions. Some trends and backgrounds were determined in study to achieve better efficiency in fracturing and coiled tubing operations for targeted formations.
When hydraulic fracturing techniques are used to stimulate production from an oil or gas well, successful job placement is often jeopardized by near-wellbore (NWB) problems. These problems may be related to the perforation entry or to the fracture width in the immediate vicinity of the wellbore. It has often been concluded that insufficient width generation in the NWB area is the result of the fracture having a very tortuous (rapidly turning or twisted) path for the first few inches or feet before adopting its generally planar shape after it grows beyond the wellbore area. In other cases, the inadequate width problem may result from the generation of several independent fracture planes instead of only one (or a few). During the early 1990's, the oil industry began to consider these problems more seriously, and many operators now use techniques to mitigate such problems before or during a fracture stimulation. The completion plan must sometimes be altered to reduce the occurrence of similar problems in future wells completed in a particular reservoir. Proppant slugs and viscous gel slugs have helped remediate this problem during several applications throughout the world.
Contrary to what we would like to believe, proppant and/or viscous gel slugs do not cure every premature screenout. Of course, some people still believe that these slugs would prevent every premature screenout if they were applied properly for the particular problem. If economics were not a real-life consideration, and every completion could be treated as an experiment, that position might be valid. In today's oil and gas exploration environment, the more practical constraints of "economic benefit" present several limitations. This paper discusses these "slug" techniques and their evolution in recent years. It also presents some of the current state-of-the-art methodologies being used. We also offer practical limits to be considered for use with these techniques. Several case histories are presented as illustrations, and suggestions for alternate completion techniques are discussed.
History and Background
There is much debate about the first use of proppant slugs in hydraulic fracturing operations and many claims to "inventor" status. Considering the typical size of fracturing treatments over the past 20 years, the original frac jobs of the late 40's and early 50's were no more than "proppant slugs" by modern standards. From the 60's through the 80's, proppant slugs were used only sporadically and seldom through a premeditated or scientific method. McMechan et al. 1 reported dramatic effects from small slugs improving perforation entry problems in very deep Okla-homa reservoirs. To some extent, this phenomenon has probably existed for 50 years. History also shows that the use of very small, 100-mesh sand added to the pad volume or just before the primary (larger size) propping agent was started in an attempt to improve fluid-loss control into natural fractures. This application was rare before the late 70's; however, as Cipolla et al.2 have reported, it continues to find significant applications today.