Formations with a bottomhole static temperature below 70 degC are very common for quite a number of Russian oil provences such as Komi, Samara Area, Orenburg, Tatarstan Bashkiria, and Eastern Siberia. Many of these formations are now being developed with proppant fracturing which incorporates a lot of flow back issues due to the various reasons including high viscosity oil, aggressive TSO designs and cycle loads on a proppant pack due to ESP change regime. There are a number of solutions to prevent proppant flow back and the most common one is usage of resin-coated proppants. At temperatures below 70degC RCP needs chemical activation in order to achieve a solid proppant pack consolidation. Depending on temperature range and coating structure various types of activators can be used. Traditionally commercial activators were used at very high concentrations that may compromise proppant pack conductivity and performance fracturing fluid. Alternative techniques are based on using fiber technologies and unconventionally shaped proppants.The majority of flowback control techniques have been tested in Volga-Urals region of Russia, Orenburg, Samara and Bashkiria areas. Novel additives that accelerate curing, RCP was successfully implemented and pumped during hydraulic fracturing on the most oil fields of Samara area. Flow back problems were observed only at extremely low temperature reservoir (Ͻ30 degrees Celcius) with highviscous (ϳ100ϩ cP) oil. Paper uncovers the details of activation process with detailed laboratory investigation for several RCPs and activators, proposes decision matrix for low temperature flow back control techniques, its applicability and design. Problem: Proppant Flow backProppant flow back is the term used to describe the problem of proppant being produced out of a hydraulically created fracture during well cleanup or reservoir production. This phenomenon can create several problems. Once removed from the fracture, proppant cannot contribute to fracture conductivity or reservoir production, moreover, productivity of the remaining fracture is severely affected. Proppant flowing back from the fracture may cause mechanical problems with downhole equipment, especially for the wells equipped with an electrical submersible pump (ESP).
Acidizing treatments in carbonates often result in significant skin decrease due to high reactivity of the formation with acids. Noticeable production increase or inability to run analysis tools after the treatment may lead to the conclusion that the matrix acidizing job was performed efficiently, when, in fact, the job was not optimized in terms of fluid volumes, acid types, wellbore coverage, and pumping rates. As a result, the final skin is not as low as it could be, and, most importantly, medium - and long-term post-acidizing production decline is faster than it could be with an optimized treatment. To overcome these concerns, an integrated approach to acidizing treatments was implemented for different oil fields in Kazakhstan. The integrated approach consists of comprehensive laboratory testing, which includes core flow tests with subsequent 3D computer tomography scanning. The tests help to determine wormholing regimes and channel geometry while providing calibration points for acid-rock interaction curves. These coefficients are used in the acidizing modeling software, which enables optimization of fluid volumes, pumping rates, and diversion strategy. The approach suggests the use of a single-phase retarded acid system is the most effective method of keeping the treatment in the dominant wormhole regime, especially at elevated temperature. The integrated approach loop is closed by the analysis of the distributed temperature sensor data to calibrate the efficiency of diversion and reservoir injectivity profile. The approach was introduced for different oil fields in Kazakhstan, with a variety of conditions: depths up to 5000 m and temperatures up to 145°C. The approach helped to optimize acid volumes by as much as 44% to achieve an optimum skin. In the mid-term perspective, this approach helped to reduce the production decline rate by at least 20%, and ongoing post-treatment analysis is even more promising.
One of the strategic targets in Yamal autonomous district, the Turonian siltstone formation, lies above the Cenomanian formation and is separated by a massive argillite barrier. Successful stimulation experience in vertical wells in the North-Kharampurskoe field during 2008 to 2010 encouraged the operator planning the next step of field exploration to consider horizontal well completions using multistage stimulation. The paper will describe pilot campaign in details. The Yamal Turonian formation was formed in a coastal marine environment with slow deposition rates and is composed primarily of siltstone. The major challenges of the Turonian formation are low permeability (∼0.5 md) and extremely high clay content—chlorite, kaolinite, illite, and mixed-layer illite-montmorillonite. The low temperature of the Turonian formation (below 80°F) also presents a significant challenge for gas production. An operator must produce at minimum drawdown to avoid hydrates creation. The shallow reservoir depth (∼ 3,000 ft) restricts recovering potential energy stored inside of the formation (initial reservoir pressure of about 1600 psi); therefore, hydraulic fracturing is a must for economic development of the Turonian formation. Selecting the correct fracturing fluid required extensive laboratory tests for compatibility and rheology adjustments. Thorough optimization of the fracturing fluid with clay stabilizer was applied during the course of this project. Additional challenges included proppant flowback tendency and inefficiency of conventional methods (resin-coated proppant) at such low temperatures. The project began by stimulating a vertical well that was used as a reference for the fracture horizontal well that was stimulated in three stages. Coring and a full logging suite were performed on the reference well, including acoustic measurements, post-frac, to obtain fracture height growth. It was shown that fracture is vertical at such depth and that it covers the whole interval without vertical growth into argillaceous barriers. Bottom hole gauges were used to complete the precise mechanical modeling of the stimulated reference well. Evaluation of the mechanical and properties were completed using E&P software platform-based simulator to optimize the multistage fracturing design in the horizontal well. This paper includes a detailed sequence of the operations performed and explains conclusions made concerning fracture geometry. The lessons learned during the assessment campaign are described. This stimulation project performed in the North-Kharampurskoe field is fundamental in development of the field and serves as important step toward unlocking the gas potential of other Turonian siltstones.
During several decades high viscous guar-based gels remained main and single fluid type on Russian fracturing market. Having high viscosity and excellent proppant carrying capacity, crosslinked gel possesses damaging nature–it results in low retained conductivity of proppant pack even in case of oxidative destructors usage (<50%). In 2016-2017 low viscosity fluids based on synthetic polymer – polyacrylamide (High Viscosity Friction reducer, HiVis FR, HVFR, Viscous slickwater) started to be actively used in North America for shale fracturing. Along with improved sand carrying capacity in comparison with conventional FR due to its elastic properties, fluid demonstrated high retained conductivity of sand packs (~80%) confirmed during laboratory investigations, firstly performed by Stim-Lab (Stim-Lab Proppant Consortium 2015 – Fracturing Fluid Cleanup of various Low Polymer Fluid Systems; Stim-Lab Proppant Consortium - 2016 – Historical and current Friction Reducer Studies). However, fracturing design and job execution on conventional sandstones in Russia significantly differs from shales stimulations, i.e. serious work was required in order to start implementation of HiVis FR (Viscous slickwater) on sandstones in Russia. First field trials of Viscous slickwater were performed in Russia in the end of 2018 on conventional sandstones owned by "Gazpromneft-Khantos" - Gazpromneft subsidiary. In spring 2019 first time in the world full scale fracturing jobs, where Viscous slickwater with only ~30 cP at 511 s-1 demonstrated high transport efficiency to carry and place ceramic proppant at moderate rates (4-4.5 m3/min), as in combination with crosslinked gel as well as single fracturing fluid. Prior HiVis FR was qualified for application on sandstones as alternative to guar-based high viscous gels, major laboratory investigations were performed on novel fluid rheology, dynamic proppant transport, mechanical fluid properties, influence of breakers, etc (Loginov at al. 2019). Later, in field trials phase, additional laboratory testing was carried out to address specific fluid performance questions. New technology field trials for "Gazpromneft-Khantos" were executed with high operational success–according to initial fracturing design. Viscous slickwater was pumped as single fracturing fluid, as well in combination with crosslinked guar gels (≥50%). Jobs were performed on vertical, inclined and horizontal wells. Despitê20 fold difference in viscosity, high proppant transport efficiency of HiVis FR allowed to place standard for South part of Priobskoe oilfield designs in case of hybrids and slightly less aggressive designs in case of 100% jobs on slickwater. Application of Viscous slickwater allowed to identify number of advantages of novel fluid over traditional guar-based fluids both in terms of operational efficiency, location and environmental footprint and fluid performance characteristics. It was shown that start production of wells treated with slickwater were ~10-20% higher, and current production rate were comparable in comparison with traditional designs with higher proppant volume. Field trials on implementation of Viscous slickwater - fluids based on polyacrylamide on low viscosity reservoirs owned by "Gazpromneft Khantos" were proven to be successful both from operational and technological point of view and have become a new milestone in history of Russian fracturing. This basis could be key to the future effective development of analogical oilfields in the world.
The fracturing fluid is the essential part of any hydraulic fracturing treatment. A borate-crosslinked guar-based fluid is one of the most commonly used types of fluid. The first mention of guar derivatives crosslinked with boron can be traced back to 1977. Scientific papers that describe boron equilibria as a function of the fluid pH can be trackedback to 1966. Comprehensive studies of the rheological behavior of borate-based fluids were performed in 1980s and 1990s, and for almost 30 years, it has been considered as a well-known topic. Recently, a few authors reported a significant decrease in viscosity of the fluid at elevated pressure. This decrease was reversible (i.e., as soon as the pressure values are moved back to the normal, the viscosity is recovers). Such effect can significantly affect the stimulation design and outcome because most of the time the slurry is affected by elevated temperatures and pressures. Still, many questions remained unanswered. One of them is the effect of crosslinker concentration/composition on the stability of the fluid at highpressure. Another is the comparison of the fluid viscosity under the ISO 13503-1 ramp at standard conditions and elevated pressure. The last one concerns the actual values of the fluid rheological parameters, n and K’, under different pressures. In this paper, we investigate the fracturing fluid behavior under high pressure. For the first time in the industry, we compare the results of ISO fluid stability testing, and the fluid shear recovery under 400-psi pressure and up to 10,500 psi. Finally, using a novel hydraulic fracturing simulator, the effect of the pressure-sensitivity of the fluid on the proppant transport, fracture geometry, and, subsequently, well productivity will be demonstrated. The findings of this paper will have noticeable impact on the design of the hydraulic fracturing treatment where borate-crosslinked fluids are used.
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