The Potential of Multiple Fractured Horizontal Wells in Layered Reservoirs (Russian)

Butter, Machiel; East, Loyd E.; Kuvshinov, Igor

doi:10.2118/102633-ru

Cited by 7 publications

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“…However, this works only for single-phase flow. Because of the high cost of hydraulic fracturing operations, industry used numerical simulations to estimate and optimize the net present value (NPV) and fracture number (Guglielmo et al 2006;Sadrpanah et al 2006;Butter et al 2006). The predictions are even when compared with analytical results.…”

Section: Introductionmentioning

confidence: 99%

New Methods to Predict Inflow Performance of Multiply Fractured Horizontal Wells under Two-Phase Condition and Optimize Number of Fracture Stages

et al. 2012

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A new method is presented to calculate the total inflow and associated productivity index (PI) under two-phase conditions by a sum of contributions from matrix and N multiple fractures using semi-analytical methods. Maximizing the net Present present value (NPV), the new inflow performance relationship (IPR) models can determine the optimal fracture stage number. Furthermore, the deliverable PI is used as an input to a network model to calculate the operating rate, taking into account the network constraints such as the node pressure, allowed flowrate, or choke in place. Through this analysis, one may determine that the horizontal well of interest may not flow at the maximum PI-it suggests that the network constraints dissipate the contribution from m stage(s) fractures. The number of fracture stages is then reset to (N-m), the IPR model is rerun, and an updated PI is imported into the network model. This process is iterated until the final optimization is achieved.This method can quickly optimize the number of fracture stages for horizontal wells under two-phase solution-gas conditions, assisting operating companies in planning field development.* Guoqing Han currently holds the faculty position at China University of Petroleum Beijing

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Section: Introductionmentioning

confidence: 99%

New Methods to Predict Inflow Performance of Multiply Fractured Horizontal Wells under Two-Phase Condition and Optimize Number of Fracture Stages

et al. 2012

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Use of Hydrajet Perforating to Improve Fracturing Success Sees Global Expansion

2008

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As shown by technical papers as early as the 1960s, our industry has long known that hydrajetting perforations or slots through cemented casing could often "bail-out" a problem well that otherwise seemed completely resistant to hydraulic fracturing attempts. For most of the first 50 years of fracturing applications, few operators had sufficient demand for the fracturing process to make it a commodity service, especially before the advent of coiled tubing (CT) services in the 1980s. Often, this type of well service was costly because of the need for both abrasive mixing and high-pressure pumping. In many cases, it was too time consuming to be practical as an "every-well" application, and lower-cost conventional explosive shape-charge perforating seemed sufficient for most wells. As oil and gas prices have drastically increased in recent years, many operators have realized that for some well conditions, the use of hydrajet perforating (HP) can improve fracture stimulation efficiency and well economics. In a few cases HP has proven to be the only way that effective fracture stimulation could be achieved. In the past few years there has been a growing acceptance among both operators and service companies that hydrajet (abrasive jetting) perforating can improve overall well economics for fracture stimulated wells in many reservoirs. Some newer methodologies have combined hydrajet perforating and hydraulic fracturing into a single, continuous, multi-stage stimulation method. For many wells needing multiple fracture stimulations, significant reductions in nonproductive time (NPT) allows for reduced well costs even when more actual fracture stages are pumped. Use of more stages has often provided significant production gains and greater recoverable reserves. Enhanced stimulation success in many moderately hard and very hard formations have proven the value of converting from shape charge perforating to hydrajetting as a stand-alone operation to avoid severe near-wellbore problems during hydraulic fracturing stimulation treatments. Since about 2000, and especially during the most recent 5 years, service providers have progressively expanded the processes, which included hydrajet perforating, especially in conjunction with hydraulic fracturing methods. This paper will review the expanding applications of hydrajet perforating in recent years, including case histories from several global applications. Background Early technical papers tell us that hydrojetting (w/o abrasives) was used with acidizing and fracture acidizing as early as 1939, primarily in zones completed open hole. However, with the incorporation of solid abrasives (hydrajetting, using abrasives) the jetting nozzles in use then could only perform for minutes before excessive erosion became a problem. The literature also reveals that around 1958 there was a renewed interest in sand-jetting and more abrasion-resistant carbide jets were developed. In May, 1961, the Journal of Petroleum Technology included three landmark publications that presented much of what had been happening since 1958 with respect to HP applications, and described other hydrajetting wellbore functions such as jetting cement from casing, cutting casing, scale removal, and other applications. The more extensive of these publications (Brown et al. 1961, and Pittman et al. 1961) had first been presented at technical conferences in October, 1960. The shorter, introductory article (Ousterhout 1961) indicated that by early in 1961 over 5,000 hydrajetting jobs had been performed with a success rate in excess of 90%; more than half of these were perforating applications. At that time, explosive/shape charge perforating was still in its infancy, with bullet perforating still common.

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PinPoint Multistage Fracturing Stimulation – Global Applications and Case Histories from Russia

2008

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Creating multiple zone stimulations in complex reservoirs presents unique challenges for the completion engineer. Effectively stimulating each individual pay interval using separate fracturing treatments can be costly and time consuming. Historically, efforts to stimulate multiple zones usually consisted of casing fracs with limited entry perforating and using sand plugs to separate zones, or tubing fracs with retrievable bridge plugs and packers. The challenge was to rethink the approach to this technology and develop more cost effective and efficient solutions. Those efforts have resulted in a new approach called pinpoint stimulation. New pinpoint stimulation methods have resulted in reduced cycle time for operators. This means doing multiple service operations in a single trip to the well. If performed individually, perforating, fracturing, setting isolation plugs, and cleaning out the wellbore for each interval can add days or weeks to a completion, delaying production-to-sales and increasing overall costs. Now, we perforate, fracture stimulate, and clean out with a single trip to the wellsite. Each treatment stage is customized for the intervals treated and many more intervals can be stimulated economically. Pinpoint multistage fracturing is available in 16 different processes for many types of well completions. In this paper, we present different techniques for a wide variety of applications and provide actual treatment data and results including recent case histories from Russia. Introduction Since the first commercial hydraulic fracturing treatment was performed by Halliburton in Velma, Oklahoma in March 1949, the industry has relied on multistage fracturing to help maximize asset value. Selectively stimulating individual intervals in the wellbore can help to keep operating costs low, reduce time to initiation of production, and improve ultimate recovery. One of the first experimental fracture treatments on record is reported to have been a four-stage pinpoint stimulation in July 1947 in the Kansas portion of the Hugoton field, which targeted four limestone gas pays at depths ranging from 2,340 ft (713 m) to 2,580 ft (786 m). That stimulation job was conducted in four separate hydraulic fracturing treatments (stages), each of which involved pumping 1,000 gal (3785 L) of napalm (thickened gasoline) through jointed tubing equipped with a cup-type straddle packer, followed by 2,000 gal (7570 L) of gasoline with 1% gel breaker. Selectively fracturing individual zones with a series of treatments was the only option possible at the time because of the equipment limitations. The available equipment was not capable of pumping the high rates, volumes, and pressures necessary to stimulate large sections of the wellbore. That began to change in the 1950s as the introduction of better casing and tubular products, more powerful pumps, and more capable wellsite equipment combined to enable operators to reach deeper, larger oil-and gas-bearing strata. By the mid-1960s, the primary method used to stimulate gas wells in the Hugoton field was to hydraulically fracture long sections of the wellbore, frequently encompassing several intervals in a single treatment, by pumping large volumes of low-cost, water-base fluids at very high rates. This reflected an industry-wide trend toward large, high-volume fracture treatments targeting several intervals in the wellbore and away from strategies allowing the selective treatment of individual intervals in a well.

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The Potential of Multiple Fractured Horizontal Wells in Layered Reservoirs (Russian)

Cited by 7 publications

References 0 publications

New Methods to Predict Inflow Performance of Multiply Fractured Horizontal Wells under Two-Phase Condition and Optimize Number of Fracture Stages

New Methods to Predict Inflow Performance of Multiply Fractured Horizontal Wells under Two-Phase Condition and Optimize Number of Fracture Stages

Use of Hydrajet Perforating to Improve Fracturing Success Sees Global Expansion

PinPoint Multistage Fracturing Stimulation – Global Applications and Case Histories from Russia

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