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Jin, F.. (CNPC Drilling Research Institute) | Shunyuan, Z.. (CNPC Drilling Research Institute) | Bingshan, L.. (CNPC Drilling Research Institute) | Chen, C.. (CNPC Drilling Research Institute) | Kedi, M.. (China University of Petroleum)
Abstract As a kind of water saving and green fracturing methodology, the innovative LPG fracturing fluid system that is developed by Gasfrac is known for its low density, viscosity and surface tension, making satisfying achievements in McCully Gasfield in Canada. However, it has not been applied by scale in China and requires further analysis. The LPG fracturing technology was analyzed technically and its physical properties were studied, including viscosities and surface tensions of water, butane and propane within various temperature ranges. A LPG fracturing phase control diagram and a fluid capillary pressure diagram were drafted. Production data of many shale gas wells in McCully block were analyzed to accomplish the fracturing flowback formula. The economical analysis of the LPG fracturing technology was completed, including the overall cost of slickwater fracturing fluid and water treatment, as well as the overall cost of LPG fracturing fluid and its integrated devices. The slickwater fracturing fluid has been widely used in China to exploit shale gas, which wastes a lot of water and does harm to environment. The LPG fracturing technology utilizes liquefied petroleum gas as the fracturing fluid that mainly consists of propane with ethane, butane, propylene and some additives, so it is harmless to formation. Compared with conventional hydraulic fracturing, the LPG fracturing fluid is mixed with chemical additives when being pumped and it becomes a kind of viscous fluid like gel, so that proppant particles may be evenly distributed in it and they don't deposit along fractures. Besides, fractures are higher and the production life of gas wells is improved. Propane mixes with natural gas completely and it may reduce the oil's viscosity after contacting it. Therefore, there is no need of flowback and water treatment procedure. Injected in a closed loop, the LPG fracturing fluid is operated via a remote computer and monitored by sensors distributed in the operation area, so that LPG leakage risk is reduced and the fracturing operation may be carried out safely. Shale gas is being widely exploited in Sichuan Province, which is located at the source of Yangtze River. In Ordos Basin limited water sources make it very costly to prepare conventional fracturing fluids. The slickwater fracturing fluid is cheaper than the LPG fracturing fluid, while water treatment costs more. All in all, LPG fracturing technology shall be recommended in China that suffers from severe environmental risks and water scarcity.
Abstract This paper describes the implementation of the first successful fracture treatments in the Carboniferous formation of the Trent Field, in the Southern North Sea. To date, two wells have been successfully fractured with indications from IPR work that the total deliverability from the Lower Trent was increased by 300%. Today the wells are flowing over 45 mmscfd from the Upper and Lower Trent with minimal drawdown. In this paper we describe the reservoir challenges of fracturing the Carboniferous formation. These challenges included deviated wellbore effects, contrasting leakoff and spurt, natural fractures in the Upper Trent, low sand-shale stress contrast and uncertainty of the principal stress azimuth. The paper describes the pre treatment tests, challenges of analyzing the mini-frac and the logic used in the final design. Because the Trent platform is not normally manned the need for no proppant flowback was critical to the success of the fracturing program. To prevent proppant flowback both wells used a 20/40 dual coated resin ISP proppant The first well took 7 days to cleanup to an acceptable flowback of <5 pounds per hour of proppant In an attempt to decrease the amount of time to cleanup the well, the second well utilized forced closure and the addition of fibers. Cleanup time was reduced to 2 days. Introduction The Trent Field located within Block 43/24 was discovered in 1991. The field is located in the Southern North Sea Gas Basin 100 miles north of East Anglia. The field contains up to 15 distinct sand-bearing units, however, only three units are commercial at this time. Of these units, the Lower Trent, which accounted for over half of gas-in-place is made up of low permeable sands (0.1–10md). Initial appraisal of the Lower Trent was a disappointing 0.5–1 mmscfd. The first fracture treatment on the Trent was performed in 1993 in Well 43/24–3. In an attempt to determine the deliverability of target zone the fracture treatment had to stay within this interval. The well was perforated with 12 spf over a 21-ft interval. This created a major challenge to control multiple fractures and height growth. In an attempt to control these factors the design called for a small pad and low pump rate. The treatment was also the first job in the North Sea to use a high temperature Borate. Unfortunately, the treatment screened out prematurely with placing only 9,000 lbs. of proppant Post evaluation indicated that the well screened out because of near wellbore tortuosity and height growth. Because of the failure from the first job and the need to successfully treat deviated wellbores, core work was performed to determine the fracture azimuth and Dynamic elastic properties. From this work it was determined that the maximum horizontal stress was 193–267 from the North which was perpendicular to what was expected in this area. This was later confirmed with borehole breakout. Additional challenges included little stress contrast, contrasting permeabilities and natural fractures in the Upper Trent. Laboratory work was performed to determine the dynamic leakoff and spurt loss in both the Upper and Lower Trent. The treatment pumped used Intermediate Strength Ceramic Proppant with RCP that utilized a dual-coat curable phenolic resin. The entire treatment was pumped with resin coated proppant to ensure that there would be no proppant flowback The resin-coated proppant was successful in attaining minimal proppant flowback However, the second treatment included fibers, which enabled the second well to cleanup in two days versus 7 days. Well and Reservoir Data Reservoir Interval. The Carboniferous formation is a highly complex fluvial system and is made up of 15 distinct sand bearing units. Of these 15 sand-bearing units only three intervals are of commercial value at this stage. P. 439^
Abstract A novel oxidizing breaker system has been developed for fracturing fluids at high temperatures. Below 200 F, the system is not active, but above 200 F, the oxidizing system aggressively attacks the polysaccharide backbone of the fracturing fluids, resulting in a complete break of the crosslinked fluids. In the presence of a gel stabilizer, an intermediate, reactive oxidizing species is formed. The result of this formation is a delayed, soluble, high-temperature oxidizing system. Controlled viscosity reduction at 200 F to 300 F in crosslinked gelled fluids with and without a gel stabilizer will be demonstrated. Testing included Model 50 viscosity profiles, high-temperature static break tests, and conductivity testing. Results from all testing showed the effect of oxidant concentration in producing a predictable, controlled break of the thermally stabilized crosslinked systems. Data were obtained in low-pH and high-pH Zr-crosslinked fluids as well as in borate-crosslinked fluids. The delayed mechanism of the new breaker system provides fluids with excellent crosslinked viscosity properties at early times with predictable, long-term viscosity reductions. Case histories show that the breaker system can be used throughout the treatment in the pad fluid, proppant-laden fluid, and flush. This paper provides data that allow significant improvements in job design. The operations engineer can obtain predictable, controlled gel degradation by using the data provided for temperature, gel type, gel stabilizers, and breaker concentration. The results are optimized treatment designs with rapid fluid recovery, improved proppant-bed conductivity, and increased well productivity. Introduction Breakers are an essential component of fracturing fluids. Ideally, a breaker should maintain high viscosity throughout the pumping of the fluid and sand. Once pumping is complete, the fluid should immediately break back to the viscosity of water. An ideal viscosity profile is shown in Fig. 1. In most cases, current technology provides a quick initial drop in viscosity followed by a slow, gradual decline in viscosity until the fluid is completely broken. Encapsulation helps achieve an improved break profile at low to moderate temperature, but above about 175 F, diffusion from the capsules becomes the determining factor because the breakers are only briefly stable at those temperatures. Improved fluids technology has provided crosslinked gels that can maintain viscosity at elevated temperatures for long periods of time. These thermally stable fluids improved overall gel viscosity and the ability of the fluid to carry proppant. However, the advancement in fluids technology to provide more stable fracturing gels limited the recovery of the fluid and ultimately the fracture conductivity. The use of breakers in high-temperature fracturing applications would provide a method to efficiently recover these thermally stable fluids. Even today, the need for breakers throughout an entire fracturing treatment above 200 F is not a generally accepted concept because of the lack of controllable breaker systems at these high temperatures. Oxidizing breakers, such as persulfate, are effective from about 120 F to about 175 F. However, these materials react too quickly at higher temperatures. The rapid oxidation causes uncontrolled breaks and premature gel degradation, which lead to the following:–poor proppant transport –insufficient fluid leakoff control –limited ability of the fluid to maintain fracture geometry Encapsulation technology can provide slow release of oxidant, providing a delay in the breaking process. However, these methods offer only limited control above 175 F, especially above 200 F and when gel stabilizers are required. Enzymes are the other major class of gel breakers. Typically, the application of enzymes is limited to lower temperatures (150 F or lower) and an optimized pH range (5 to 8). P. 175^
Letichevskiy, Alexander (JSC-Samaraneftegaz Rosneft) | Nikitin, Alexey (JSC-Samaraneftegaz Rosneft) | Parfenov, Alexey (JSC-Samaraneftegaz Rosneft) | Makarenko, Vitaliy (JSC-Samaraneftegaz Rosneft) | Lavrov, Ilya (JSC-Samaraneftegaz Rosneft) | Rukan, Gleb (Schlumberger) | Yudin, Alexey (Schlumberger) | Ovsyannikov, Dmitry (Schlumberger) | Nuriakhmetov, Ruslan (Schlumberger) | Gromovenko, Alexander (Schlumberger)
Abstract A characteristic feature of oil fields in the Samara region which main oil reserves are concentrated in terrigenous formations is considered to be a high level of exploration and depletion. One of the main challenges the solution of which will allow to maintain the current level of production is the systematic application of modern technologies for the oil inflow stimulation of small and hard-to-reach reservoirs with unfavorable geological and physical conditions. Under these circumstances the classical fracturing method with regular proppant injection has no the proper effect, what forces the oil producing companies to recourse to more efficient technologies. Gradually deteriorating geological conditions limit both the size of the proppant pumped and the tonnage of the whole hydraulic fracturing operation, not allowing to achieve the optimal "formation-well" connection. To optimize the fields development process in 2015-2016 four pilot operations were performed with a new technology for the region - the cluster fracturing. When it is performed, the proppant is being pumped with "pulses" alternating with self-dissolving fibers, thus achieving a highly conductive fracture structure that removes the restrictions for hydrocarbons inflow occurring during conventional fracturing. The development objects, treated with channel hydraulic fracturing, were sandstones of the Devonian system (D1, D3, Dk) of the Kuleshovskoye oil field, which was discovered as far back as 1959 and being the second largest in the Samara region. These formations are characterized by low reservoir properties and located at a much greater depth in comparison with the main oil reservoirs. The obtained results showed that the wells after the cluster fracturing demonstrated a productivity coefficient higher by 47%, the oil production rate increased by 1.56 times as compared to the wells with the conventional fracturing. Good production results were obtained due to the pad stage percent decreasing, a reduction of the fluid volume (when converted to the equivalent mass of standard fracturing), and the use of higher proppant concentrations.
Abstract Fracturing treatments using treated water and very low proppant concentrations ("waterfracs") have proven to be surprisingly successful in the East Texas Cotton Valley sand. This paper presents field and production data from such treatments and compares them to conventional frac jobs. We also propose possible explanations for why this process works. Introduction Hydraulic fracturing is the key technology to develop tight oil and gas reservoirs. Although millions of research dollars have been spent to date, much controversy remains about optimizing fracture design. Rock mechanics and fluid transport phenomena in hydraulic fracturing are still poorly understood. The processes are very complex with a host of unknowns. Measuring even one critical value such as net fracture treating pressure constitutes a difficult problem. Hydraulic fracture research and development has put a lot of effort into effective placement of propping agents to provide and maintain fracture conductivity. For this purpose the service industry has developed sophisticated fracturing fluid systems and an extensive recipe of chemical additives. The fluid system is engineered to change viscosity during its journey from the surface to the fracture and afterwards during fracture cleanup. The sole reasons for these fluid designs is to place proppant, minimize formation damage and ensure proper cleanup. In turn, the proppant has no function other than maintaining a conductive fracture during well production. What would happen though if the fracture actually retains adequate conductivity with very little or no proppant?–Rock fractures often have rough surfaces. After the fracture closes, the residual aperture distribution can be very heterogeneous in all three dimensions forming a very conductive path even at high closure stresses. - Proppant along with gel residue could actually impair fracture permeability and its ability to cleanup. –Fracture extension and cleanup is easier to achieve with low viscosity fluids. Fracture extension is the key design parameter in tight reservoirs. The above points may have a tremendous impact on the fracturing operation. Gelling agents, proppant and associated chemical additives comprise a large part of fracturing costs. In early literature, "self-propping" and "partial monolayers" of fractures has been discussed. In general though, the industry has discarded the idea. In the naturally fractured Austin Chalk the so-called "waterfrac treatments" are pumped with no propping agents. They are very successful. Why it works is still generally unknown. The hydromechanical response of natural fractures has been addressed in rock mechanics literature. It is an extremely important issue in the field of underground nuclear waste disposal. The effect of normal stress and shear stresses on a fracture (natural and artificial) dictate its conductivity. The ramifications of these forces on fracture propagation are just now beginning to be investigated (multiple fractures). Description of "Waterfracs" The following outlines the general pumping schedule (from here on, the treatments will be referred to as "waterfracs"). P. 457