Limited-Entry Frac Applications on Long Intervals of Highly Deviated or Horizontal Wells

McDaniel, B.W.; Willett, Ron; Underwood, P.J.

doi:10.2118/56780-ms

Cited by 34 publications

(6 citation statements)

References 20 publications

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“…This study compares the distribution of 40/70 mesh sand, which has a median particle diameter of 0.312 mm, to that of 100 mesh sand, which has a median particle diameter of 0.1854 mm. The specific gravity of the sands was 2.65 g/cm 3 . All data for the 100 mesh sand were obtained by Alajmei and Miskimins.…”

Section: Methodsmentioning

confidence: 99%

Experimental Investigation of the Impact of Particle Size on Its Distribution within a Horizontal Wellbore

Alajmei,

Budiman,

Aljawad

2023

ACS Omega

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Fracture conductivity is directly affected by an uneven proppant distribution, which affects the productivity of a well. The distributions of 40/70 mesh white sand compared to 100 mesh brown sand in a horizontal wellbore were investigated in this study. The apparatus used to conduct these tests was a 30 ft-long transparent horizontal wellbore with three perforation clusters. The proppant distribution was examined experimentally by injecting slurries at three different injection rates ranging from 20 to 75 gpm. The proppant concentration of both sands increased for each test from 0.5 to 2 ppg. The proppant concentrations and injection rates were used with multiple perforation configurations (orientations) including extreme limited entry perforations. The results confirmed that the injection rates significantly affected the proppant distributions across the different perforation clusters. Even distribution of the 40/70 mesh sand can be obtained using a 1 shot per foot (SPF) top perforation design. The 100 mesh sand was evenly distributed using a 4 SPF perforation configuration. The settling percentage was calculated for each experiment to determine the quantity of 40/70 mesh and 100 mesh sand settled at the bottom of the horizontal wellbore. A carrier fluid can suspend the sand more effectively with a higher injection rate, reducing the average sand settling to 2% in the case of the 100 mesh sand compared with approximately 8% for the 40/70 mesh sand at similar injection rates. This research confirms the need to use a 100 mesh at high injection rates to reduce sand settling during the hydraulic fracturing process.

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Section: Methodsmentioning

confidence: 99%

Experimental Investigation of the Impact of Particle Size on Its Distribution within a Horizontal Wellbore

Alajmei,

Budiman,

Aljawad

2023

ACS Omega

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“…In general, because of injection rate limitation issues, this type of solution requires a cased, cemented completion (McDaniel et al 1999;Roudakov and Rohwer 2006). With this method, many positions are stimulated at once, thus making the stimulation process easy to perform.…”

Section: Limited-entry Multiple-fracture Stimulationmentioning

confidence: 99%

Consideration for Future Stimulation Options Is Vital in Deciding Horizontal Well Drilling and Completion Schemes for Production Optimization

Surjaatmadja

McDaniel

Case

et al. 2008

SPE Production &Amp; Operations

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Summary Many horizontal wells have been completed without plans for stimulation. Often, horizontal wells were not planned for stimulation, because the belief at the time of completion was that horizontal wellbores eliminate the need for hydraulic fracturing stimulation. This presumption has turned out to be false. Often, by the time it is discovered that a horizontal well needs to be stimulated, it cannot be stimulated effectively because of mechanical or reservoir limitations. This regrettable outcome may have been avoided if extensive preplanning had included consideration for future stimulation. Such preplanning may be limited—not only to the already extensive plans for prospective stimulation activities and selection of the most promising stimulation methods—but for all activities required during the life of the well. History of Horizontal Wells Before 1990, US horizontal wells totaled less than 300. By 2004, horizontal wells in the US still numbered less than 4,000, with fewer than 14,000 worldwide (Protecting Our Water 2004; Horizontal and Multilateral 1999). It is likely that most of the horizontal wells drilled before 1990 have depleted to an unsatisfactory production level, now making stimulation a necessity (East et al. 2004), and the US drilling pace for horizontal wells in low-permeability reservoirs has increased since 2005. Horizontal wells were first drilled in the 1930s, primarily to expose more hydrocarbon-producing rock. Often though, cost and/or risk prevented these types of completions (Ranney 1939). To competitively achieve the same purpose, around 1949, service companies began to offer hydraulic fracturing-stimulation services that proved to be very effective in reaching the unexposed hydrocarbon. This success resulted in a temporary decline of horizontal well technologies, but in the early 1970s, more economical solutions in horizontal well drilling became available. Often during that time, the primary objective was to eliminate the need for costly stimulation and completions. Eventually, operators began to realize that many of their horizontal wells were not producing as expected. Their options were to abandon the wells, be content with the low production, or stimulate. Usually, hydraulic fracturing stimulation was the desired option, but because the wells had not been completed with future stimulation treatments in mind, fracture stimulations often did not produce satisfactory results. Even when the wells were cased and cemented, many stimulation treatments were marred by screenouts and economically infeasible production increases. How Horizontal Wells Differ Stimulation options in horizontal wells are heavily influenced by the type of completion selected during the design phase. This consideration is less critical with vertical wells, whereby in most cases, any stimulation method can be implemented without unusual precompletion stimulation planning. A primary difference with horizontal drilling is hydraulic fracture plane position relative to the wellbore. Fig. 1 shows a vertical well (a) that intersects the formation, creating Fractures 1, 2, and 3. Theoretically, no matter what the hydraulic fracture direction, any resulting fracture (i.e., 1, 2, or 3) connects to the wellbore in a similar fashion. That is, a large portion of the fracture connects the wellbore either axially or longitudinally. Of course, this theory assumes that fractures are always vertical; which, as will be discussed later, may not be the case. After the wellbore is laid down (as in view b), and relative to the wellbore, hydraulic fractures can be positioned in any relative direction imaginable. To further complicate matters, horizontal wells as defined in the industry, in most cases, are not precisely horizontal. Slants, dips, and "up-and-downs" are often designed into (or an unintentional result from) the drilling program (a complicated up-and-down horizontal well is shown in Fig. 2). Obviously, most horizontal or deviated wells are not as complicated as the one shown, and often their shape is controlled (and limited) by the capability of the drilling company performing the operation. Another controlling factor is rock characteristics (e.g., the presence of brittle hard rock may incapacitate steering mechanisms in many drilling systems).

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“…After all groups of the perf clusters have been fractured, hydraulic pressure is removed from the formation, and the fracturing equipment is removed from the location. The primary consideration is usually zonal isolation and adequate stimulation for all zones (McDaniel et al 1999). With limited-entry perforating of an entire lateral, multiple treatment intervals can be perforated in one trip without having to pull out of hole (POOH).…”

Section: Introductionmentioning

confidence: 99%

“…This decrease is very sudden and significant compared to the later-time semi-steadystate erosional effects. When fracturing long intervals in horizontal wells, this pressure decrease may result in rapid cleanup of the first set of perforations, which can begin to accept a larger proportion of volume (rate) at the expense of perforations down the interval (McDaniel et al 1999). Consequently, the perforations nearer the toe might not encounter any treatment fluid or proppant until later, thereby creating a disproportionately fractured interval, although those wells had six to eight sets of perforations located in a 3,000-ft lateral being treated in one stage.…”

Section: Introductionmentioning

confidence: 99%

Evaluation and Optimization of Proppant Distribution in Multistage Fractured Horizontal Wells: A Simulation Approach

Bokane

Jain

Crespo

2014

Day 1 Tue, September 30, 2014

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Multistage hydraulic fracturing has become the key technology for completion of horizontal and vertical wells. The perf and plug method is the most commonly used staging method. During each stage, multiple perforation clusters are used, attempting to create a separate transverse fracture at each cluster. How these clusters are placed can significantly affect both short-and long-term production performances. Simultaneous creation of multiple fractures is a cost-effective and time saving method for stimulating both vertical and horizontal wells. Multistage fracturing is an effective method in terms of completion efficiency; however, achieving even proppant distribution to each cluster is an intricate task that can be challenging within the industry.Numerical simulations predict uneven proppant distribution of the fluid streams entering different perforation clusters. Field data indicates, in many cases, that some of the clusters do not contribute to production. This led to hypothesizing that actual proppant and fluid distribution along the stimulated clusters can differ from the assumed uniform distribution.This paper presents an extensive optimization study and investigation of proppant transport in different perforation clusters within a single stage using computational fluid dynamics (CFD) techniques. Effects of proppant and fluid properties (e.g., variable mass flow rate, variable proppant and fluid densities, and viscosity of the fluid) were analyzed, while maintaining outside-casing parameters constant. Validation of empirical proppant transport CFD simulation results are compared to experimental test data.The CFD results indicate that proppant transport can be accurately modeled when the effects of single particle settling, density driven flow, particle velocity profiles, and slurry rheology are all considered. Understanding the behavior of proppant and achieving more even proppant distribution among perforation clusters can help the industry. The investigation demonstrates that CFD is an effective tool for optimizing proppant distribution among perforation clusters and enhancing production.

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Limited-Entry Frac Applications on Long Intervals of Highly Deviated or Horizontal Wells

Cited by 34 publications

References 20 publications

Experimental Investigation of the Impact of Particle Size on Its Distribution within a Horizontal Wellbore

Experimental Investigation of the Impact of Particle Size on Its Distribution within a Horizontal Wellbore

Consideration for Future Stimulation Options Is Vital in Deciding Horizontal Well Drilling and Completion Schemes for Production Optimization

Evaluation and Optimization of Proppant Distribution in Multistage Fractured Horizontal Wells: A Simulation Approach

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