Results
Abstract We developed a high-resolution fracture productivity calculator to enable fast and accurate evaluation of hydraulic fractures modeled using a fine-scale 2D simulation of material placement. Using an example of channel fracturing treatments, we show how the productivity index, effective fracture conductivity, and skin factor are sensitive to variations in pumping schedule design and pulsing strategy. We perform fracturing simulations using an advanced high-resolution multiphysics model that includes coupled 2D hydrodynamics with geomechanics (pseudo-3D, or P3D, model), 2D transport of materials with tracking temperature exposure history, in-situ kinetics, and a hindered settling model, which includes the effect of fibers. For all simulated fracturing treatments, we accurately solve a problem of 3D planar fracture closure on heterogenous spatial distribution of solids, estimate 2D profiles of fracture width and stresses applied to proppants, and, as a result, obtain the complex and heterogenous shape of fracture conductivity with highly conductive cells owing to the presence of channels. Then, we also evaluate reservoir fluid inflows from a reservoir to fracture walls and further along a fracture to limited-size wellbore perforations. Solution of a productivity problem at the finest scale allows us to accurately evaluate key productivity characteristics: productivity index, dimensional and dimensionless effective conductivity, skin factor, and folds of increase, as well as the total production rate at any day and for any pressure drawdown in a well during well production life. We develop a workflow to understand how productivity of a fracture depends on variation of the pumping schedule and facilitate taking appropriate decisions about the best job design. The presented workflow gives insight into how new computationally efficient methods can enable fast, convenient, and accurate evaluation of the material placement design for maximum production with cost-saving channel fracturing technology.
- Europe (1.00)
- North America > United States > Texas (0.46)
- Asia > Russia > Ural Federal District (0.46)
- Europe > Russia > Northwestern Federal District > Barents Sea > Pechora Sea > Timan-Pechora Basin > Prirazlomnoye Field (0.99)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug > Purovsky District > West Siberian Basin > Nadym-Pur-Taz Basin > Block V > Urengoyskoye Field > Achimov Formation (0.99)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug > Purovsky District > West Siberian Basin > Nadym-Pur-Taz Basin > Block IV > Urengoyskoye Field > Achimov Formation (0.99)
- (4 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.93)
- Well Completion > Completion Installation and Operations > Perforating (0.86)
Summary This study focuses on the development of an analytical model to predict the long-term productivity of channel-fractured shale gas/oil wells. The accuracy was verified by comparing productivity calculated by the proposed model with numerical results. Sensitivity analysis was conducted to analyze significant parameters on the performance of channel fracturing. Field application of the model was conducted using production data obtained from an Eagle Ford Formation dry gas well, which was completed using channel fracturing. The procedure for estimating reservoir and stimulation parameters from production data was provided. The results indicated that the equivalent fracture width obtained from our model is consistent with the inversion of cubic law. Comparison with numerical simulations demonstrated that the proposed model might under- or overestimate well productivity, with mean absolute percentage error (MAPE) values of less than 8%. Sensitivity analysis indicated that, with the increase of fracture width, fracture half-length, and matrix permeability, the productivity of channel-fractured wells increases disproportionately. In addition, well productivity will increase as the ratio of the pillar radius to the length of channel fracture decreases, provided that the proppant pillars are stable and the fracture width is held constant. Under the conditions of smaller fracture width and larger matrix permeability, the effect of using channel fracturing to increase well productivity is more significant. However, as the fracture width becomes large, the benefits of channel fracturing will diminish. The case study indicated that the shale gas productivity estimated by the proposed model matches well with field data, with MAPE and R of 12.90% and 0.93, respectively. The proposed model provides a basis for optimizing the design of channel fracturing.
- South America (1.00)
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (0.89)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (18 more...)
Channel Fracturing Extension to Low-Temperature Formations. Field Case Studies in Russia.
Yudin, Alexey (Schlumberger) | Glaznev, Ivan (Schlumberger) | Lyapunov, Konstantin (Schlumberger) | Loznyuk, Oleg (Rosneft) | Korolev, Alexandr (Rosneft) | Khamidov, Timur (Rosneft) | Prokhorov, Alexey (Rosneft) | Rylance, Martin (BP Exploration)
Abstract Channel fracturing technology has been a key enabler to unlocking hydrocarbon production from low-permeability formations in Russia for 10 years, by minimizing treatment costs and improving operational efficiency. However, an intrinsic limitation existed for candidate selection because the technique requires post-job dissolution of the fiber that is a principal component of the success of achieving efficient channel fracturing behavior. This set a lower temperature limitation of 60°C, such that formations with temperatures below this value were not recognized as potential candidates. This project was aimed at eliminating the temperature limitation and thereby enhancing the potential candidate pool for application. The channel fracturing technique creates infinite-conductivity channels within a fracture, using a proppant-pulsing technique delivered by the surface equipment. Proppant structures are consolidated and transported along the fracture by means of fibrous material, which then degrades in the channels and proppant pillars within days after the treatment, conventionally because of the high formation temperature. Expanding hydraulic fracturing into new low-temperature oil provinces such as Eastern Siberia and the Turonian formation in the Yamal region called for adjustment in the channel fracturing technique. Specifically, surface equipment was used in a modified mode to alter the pumping schedule of the fiber additive to add fiber in pulses that are synchronized with proppant pulses. The new channel fracturing methodology was designed and tested under laboratory conditions initially and then subsequently applied in several low-temperature (20 to 30°C) oil and gas fields/wells in Russia. The first campaign yielded positive results. New software and equipment adjustments allowed for precise and accurate synchronization that resulted in fiber-free channels. The first productivity results also illustrated the potential of the technology to match or exceed the planned hydrocarbon production. The main advantages of the channel fracturing technique remained unchanged—improved barrels/dollar ratio by up to 10% compared with conventional methods and fracturing cycle operational efficiency reduction of up to 25% as compared with standard techniques. Thus, the temperature limitation was removed, leaving one major criterion for channel fracturing applicability: rock competency to hold channels open and stable throughout the life of the fracture. The study breaks new ground in the stimulation of low-temperature formations by extending the channel fracturing technique, well-recognized in the traditional basins of Russia. The project includes laboratory testing and real field examples from two regions of Russia—the first campaigns.
- Europe > Russia (1.00)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug > Purovsky District (0.29)
- North America > United States > Texas > Dawson County (0.24)
- Europe > Russia > Northwestern Federal District > Barents Sea > Pechora Sea > Timan-Pechora Basin > Prirazlomnoye Field (0.99)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug > Purovsky District > West Siberian Basin > Nadym-Pur-Taz Basin > Block V > Urengoyskoye Field > Achimov Formation (0.99)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug > Purovsky District > West Siberian Basin > Nadym-Pur-Taz Basin > Block IV > Urengoyskoye Field > Achimov Formation (0.99)
- (4 more...)
Modeling of Fracture Width and Conductivity in Channel Fracturing With Nonlinear Proppant-Pillar Deformation
Zhu, Haiyan (Chengdu University of Technology, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, and Institute of Mechanics, Chinese Academy of Sciences) | Zhao, Ya-Pu (Institute of Mechanics, Chinese Academy of Sciences and University of Chinese Academy of Sciences) | Feng, Yongcun (University of Texas at Austin) | Wang, Haowei (Southwest Petroleum University) | Zhang, Liaoyuan (Sinopec Shengli Oilfield Company) | McLennan, John D. (University of Utah)
Summary Channel fracturing acknowledges that there will be local concentrations of proppant that generate high‐conductivity channel networks within a hydraulic fracture. These concentrations of proppant form pillars that maintain aperture. The mechanical properties of these proppant pillars and the reservoir rock are important factors affecting conductivity. In this paper, the nonlinear stress/strain relationship of proppant pillars is first determined using experimental results. A predictive model for fracture width and conductivity is developed when unpropped, highly conductive channels are generated during the stimulation. This model considers the combined effects of pillar and fracture‐surface deformation, as well as proppant embedment. The influence of the geomechanical parameters related to the formation and the operational parameters of the stimulation are analyzed using the proposed model. The results of this work indicate the following: Proppant pillars clearly exhibit compaction in response to applied closure stress, and the resulting axial and radial deformation should not be ignored in the prediction of fracture conductivity. There is an optimal ratio (approximately 0.6 to 0.7) of pillar diameter to pillar distance that results in a maximum hydraulic conductivity regardless of pillar diameter. The critical ratio of rock modulus to closure stress currently used in the industry to evaluate the applicability of a channel‐fracturing technique is quite conservative. The operational parameters of fracturing jobs should also be considered in the evaluation.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia > China (1.00)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (13 more...)
First in Russia Large-Scale Implementation of the Channel Fracturing Technology in Horizontal Wells
Yudin, Alexey (Schlumberger) | Sypchenko, Stella (Schlumberger) | Gromovenko, Alexander (Schlumberger) | Romanovskiy, Rostislav (Schlumberger) | Chebykin, Nikolay (Gazpromneft) | Serdyuk, Andrey (Gazpromneft) | Bukharov, Dinar (Gazpromneft) | Faizullin, Ildar (Gazpromneft) | Churakov, Artem (Gazpromneft)
Abstract Main producing horizons of the southern license block of the Priobskoe oil field are low-permeable sandstone formations AS10–AS12. Here, horizontal drilling and multistage stimulation (MSS) involving hydraulic fracturing have proved to be an effective way of field development. Full-scale testing of the channel fracturing technology has become the next stage of MSS optimization. This paper is dedicated to analyzing the efficiency of this method based on data from 40 wells. Centered around creation of channels inside the fracture, the new method of hydraulic fracture allows better reliability of proppant placement without conductivity restraint; this is achieved by pulsing the proppant on surface, and use of fibers. Moreover, the channel fracturing technique provides significant savings in materials needed for a stimulation job – particularly, up to 45% of proppant and up to 20% of fluid – accelerating bringing-in of the as well as reducing the environmental footprint. The screenout risk is mitigated by pulsing the clean fluid and using fibers while using higher proppant concentrations at the same time. Over the course of three years, more than 240 channel fracturing jobs were executed in 43 wells. This paper contains a detail analysis of performance of the wells put on production with implementation of the new MSS technique, compared to neighbor wells where conventional stimulation techniques were used. The wells are divided into groups, e.g. by fracture direction (transverse and longitudinal) and water content in the area, i.e. water-free sections and high water cut sections. The obtained production data proves that wells stimulated with channel fracturing show at least the same efficiency than wells where conventional fracturing was used, and involve better utilization of less resources. The project described in this paper is the first experience of mass use of channel fracturing technique for horizontal wellbores in Russia. Lessons learnt from this experience, efficiency analysis, and applicability criteria defined in the scope of this project will help assess the potential of this new technique for other oil and gas fields in Russia.
- Europe > Russia (0.95)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.52)
- North America > United States > Texas (0.48)
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (2 more...)
Abstract To provide designed oil production and to minimize non-productive time new approaches in hydraulic fracturing have been tried and introduced for several years in Uvat project. During this optimization process, several new technologies were pilot tested including fiber-laden fluid, rod-shaped proppant and channel fracturing technique. The main goal was to improve fracturing fluid reliability and to decrease the risk of premature screen-outs in combination with more aggressive fracturing design to maximize oil production. Uvat project oil field is located in Western Siberia. Jurassic formation is the main oil producer from the field, presented by significant net height (up to 45 m), relatively high permeability which varies in wide range from 2 md to more than 50 mD. The formation temperature is 80-90°C. The requirements to fracture geometry is gradually increase in these conditions. The greater fracture width must be accompanied with sufficient effective fracture half-length. This goal cannot be achieved with standard hydraulic fracturing techniques because of limitations in proppant pack conductivity. Besides, the more aggressive design is associated with the higher risk of premature job screen-out that consequently results in non-productive time. Paper describes the results of pilot projects for the following new technologies introduction: fibers that allow better proppant distribution in the fracture and decrease polymer concentration without sacrificing proppant transportation ability of the fluid (the new generation of fibers was implemented which is for low temperature formation); rod-shaped proppant to prevent particles flowback and to increase fracture conductivity; channel fracturing technology that allows to decrease treatment costs and risk of premature screen-out while keeping or even increasing the flow capacity of the fracture. In channel fracturing application a proppant is added in short pulses alternated with clean fluid pulses. This becomes even more vital in remote locations as the same stimulation result can be achieved with less proppant amount replaced by clean fluid pulses that leads to decrease in spending on logistics and time optimization for fracturing job. The manuscript describes the candidate selection methods for re-fracturing jobs and states the main success criteria (such as presence of formation energy and current skin calculation). The authors represent comparative analysis of horizontal wells and multistage fracturing effectiveness in low productive regions resulted in high incremental oil rate when compared to vertical wells with a single fracture.
- Europe (1.00)
- Asia > Russia > Ural Federal District > Tyumen Oblast (1.00)
- North America > United States (0.68)
- Europe > Russia > Volga Federal District > Orenburg Oblast > Volga Urals Basin > Tsarichanskoye Field (0.99)
- Asia > Russia > Ural Federal District > Tyumen Oblast > West Siberian Basin > Ust-Tegussky License Area > Uvat Fields (0.99)
- Asia > Russia > Ural Federal District > Tyumen Oblast > West Siberian Basin > Ust-Tegussky License Area > Ust-Tegusskoye Field (0.99)
- (17 more...)
Future Trends for Tight Oil Exploitation
Zhang, K.. (University of Calgary) | Sebakhy, K.. (University of Calgary) | Wu, K.. (University of Calgary) | Jing, G.. (University of Calgary) | Chen, N.. (University of Calgary) | Chen, Z.. (University of Calgary) | Hong, A.. (University of Stavanger) | Torsæter, O.. (Norwegian University of Science and Technology (NTNU))
Abstract In this paper, production characteristics of tight oil reservoirs are summarized and analyzed, the investigated reservoirs include Cardium sandstone reservoir and Pekisko limestone reservoir. The phenomenon that gas and oil or water and oil are co-produced at an early stage of exploitation has been observed. In addition, water cut of many tight oil producers remains constant or undergoes reduction as production proceeds within first 36 months. Since an oil rate drops quite a lot in the first year's production of tight oil reservoirs, reservoir simulations are run to investigate an effect of different parameters on tight oil production. Randomized experiments are created with geological and engineering parameters as uncertain factors and an oil rate as the response factor. The method of analysis of variance (ANOVA) is used to analyze the difference between group means and to determine statistical significance. Reservoir properties such as permeability, pressure, wettability, oil API, and oil saturation and engineering parameters including a fracture stage and well operations have tremendous effects on oil production. Oil recovery factor increment in tight oil reservoirs highly depends on enlarging a contact area, improving oil relative permeability, reducing oil viscosity and altering wettability. Future research and development trends in tight oil exploitation are highlighted. As primary recovery is quite low in tight oil reservoirs, the multistage fracturing technology is a necessity and it must be conducted based on a deep understanding of petrophysical and geomechanical properties. Water alternating gas (WAG) seems the best fit for tight oil exploitation. The way to improve WAG performance, including CO2 foam stabilized with surfactant or nanoparticles, low salinity water or nanofluids alternating CO2, will earn more and more attention in the future of tight oil development.
- Asia (1.00)
- North America > Canada (0.70)
- Europe (0.69)
- (3 more...)
- Geology > Geological Subdiscipline > Geomechanics (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.58)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Buffalo Field > Red River Formation (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (32 more...)
Abstract Channel fracturing combines geomechanical modeling, intermittent proppant pumping and degradable fibers and fluids to attain heterogeneous placement of proppant within a hydraulic fracture. The aim of this well stimulation technique is to promote the formation of stable voids or streaks within the proppant pack which serve as highly conductive channels for transport of oil and gas throughout the hydraulic fracture. More than 10,000 channel fracturing treatments have been performed in over 1,000 wells during the last three years in shale-, carbonate-, and sandstone-rich reservoirs worldwide. The collective dataset on job execution and well performance shows the following trends: (a) low occurrence of near wellbore screen-outs (>99.9% of all treatments achieving 100% proppant placement); (b) reduction in the amount of proppant required to complete treatments (in average, 43% less proppant than conventional techniques aiming at placing a homogeneous proppant pack as implemented in offset wells); (c) average initial and long-term well productivity and flowing pressures consistently meeting or exceeding those of wells completed with conventional fracturing techniques. This paper summarizes findings from a comprehensive technical study focused on ascertaining the enabling mechanisms for these trends. Results from laboratory experiments (large-scale slot flow, conductivity, proppant settling), yard tests (well site delivery characteristics, proppant slug integrity), and well performance evaluations (surface treatment data, well production data and reservoir simulations supported by history matching) are analyzed collectively to reach the following assessments: (a) heterogeneous proppant placement is achieved; (b) the low incidence of screen-outs is the result of the combination of reduced usage of proppant and intermittent pumping of proppant-free, fiber-laden slugs ("sweeps") which mitigate accumulation of proppant in the near-wellbore area; (c) well productivity trends are driven by the concomitant occurrence of enhanced fracture conductivity - enabled by the presence of heterogeneities within the proppant pack- and the development of larger fractured area within the reservoir effectively contributing to production. The development of larger effective contact area is enabled by the use of fibers, which enhance proppant transport within the fracture and mitigate proppant settling.
- North America > United States > Texas (1.00)
- Europe (0.68)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- South America > Argentina > Neuquen > Neuquen Basin > Loma La Lata Field (0.99)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (8 more...)
First Channel Fracturing Applied in Mature Wells Increases Production from Talinskoe Oilfield in Western Siberia
Kayumov, Rifat (Schlumberger) | Klyubin, Artem (Schlumberger) | Yudin, Alexey (Schlumberger) | Enkababian, Philippe (Schlumberger) | Leskin, Fedor (TNK-BP) | Davidenko, Igor (TNK-BP) | Kaluder, Zdenko (TNK-BP)
Abstract In the last two decades, hydraulic fracturing has become a routine completion practice in most oilfields producing from the low- and medium-permeability Jurassic formations in western Siberia. To optimize hydraulic fracture conductivity, operators and service companies were progressively decreasing polymer loading in fracturing fluids, developing new polymer-free fluids, implementing foams as fracturing fluids, increasing proppant size and concentration, enhancing polymer breaker performance, increasing breaker concentration, and implementing the tip screenout technique. All these methods have some positive impact on proppant pack conductivity but lead to higher risk of premature screenout. The intrinsic limitations stem from the fact that conductivity is created by the proppant pack, which physically limits permeability. The new channel fracturing technique allows development of an open network of flow channels within the proppant pack; thus, the fracture conductivity is enabled by such channels rather than by flow through the pores between proppant grains in the proppant pack. The channel fracturing technique is capable of increasing fracture conductivity by up to two orders of magnitude. Talinskoe field, located near Nyagan, Russia, produces from a series of Jurassic sublayers at depths of 2270 to 2700 m. Several oil-saturated sandstone sublayers are separated by shale barriers, and their development is conducted separately. For some wells, production from bottom sublayers JK10 and JK11 became uneconomical due to injection water breakthrough or low liquid rates. Production in these wells was switched to upper layers JK2 through JK9 after perforation and stimulation operations. Five of these wells were stimulated with the channel fracturing technique. Six-month of post-frac production data were compared with production data from eight offset wells stimulated recently via conventional hydraulic fracturing. The wells stimulated with the channel fracturing technology showed an average productivity index about 51% higher. This production effect still remains positive. The absence of screenouts confirmed reliability in proppant placement observed in other projects worldwide. The successful implementation of the channel fracturing technique in brownfield development is described in detail with a theoretical and operational review, results from laboratory experiments, and analysis of the production results in comparison with conventional fracturing.
- Europe (1.00)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (1.00)
- North America > United States > Texas (0.94)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.34)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (10 more...)
Implementation of Relative Permeability Modifiers in Krasnoleninskoe Oil Field: Case Histories
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.
- North America > United States (1.00)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (1.00)
- Research Report > Experimental Study (0.48)
- Research Report > New Finding (0.34)
- Geology > Mineral (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug > Purovsky District > West Siberian Basin (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Talinskoye Field (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Kamenny License > Krasnoleninskoye Field (0.99)
- (15 more...)