A New, Effective Matrix Stimulation Diversion Technique

Paccaloni, G.

doi:10.2118/24781-pa

Cited by 53 publications

(17 citation statements)

References 13 publications

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“…In the absence of diverters, this means that injection rate must increase over time. For example, the "Maximized Pressure Differential and Injection Rates" (MAPDIR) technique (Paccaloni, 1995) was shown effective in a large number of field trials. Prima facie, it seems likely that the injection rate to best initiate the wormhole at the wellbore would be different from the best injection rate to extend wormholes several feet out into the reservoir.…”

Section: Optimal Breakthrough Strategiesmentioning

confidence: 99%

Pore-Network Modeling of Carbonate Acidization

Tansey

2014

SPE Annual Technical Conference and Exhibition

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Carbonate reservoirs represent a significant portion of global hydrocarbon reserves. Injecting strong acids around the wellbore of carbonate wells can significantly increase near-wellbore permeability. A pore-network model is developed to capture permeability response of carbonates to acid stimulation. A novel pore-scale mass-transfer coefficient and pore-merging criterion are developed using finite element simulations. Preliminary results are able to reproduce the expected trends in permeability increase and capture the gamut of different dissolution regimes. Future work will focus primarily on using advanced subdomain coupling techniques to simulate much larger domain sizes to investigate the effects of domain size and determine a representative elementary volume.

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Section: Optimal Breakthrough Strategiesmentioning

confidence: 99%

Pore-Network Modeling of Carbonate Acidization

Tansey

2014

SPE Annual Technical Conference and Exhibition

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“…The objective in these treatments is to divert or, better still, prevent fluid flow during production. Gels have also been widely used to divert fluids during the injection stages of remedial treatments, such as acid stimulations (23,24) , control of slug viscosity leading to improved acid placement. Modelling of gel placement for water shutoff (25)(26)(27) and acid stimulation (28) treatments has helped improve the understanding of how parameters such as downhole temperatures, flow rates, and chemical reaction rates impact the treatment.…”

Section: Gel Diversion Technologymentioning

confidence: 99%

Modelling Scale Inhibitor Squeeze Treatments in High Crossflow Horizontal Wells

Mackay¹

2000

Journal of Canadian Petroleum Technology

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Modeling scale inhibitor treatments in horizontal wells is emerging as an important field of research due to the need to reduce the cost of treating wells that may be thousands of feet long. Simulation studies performed using recently developed modeling tools have led to recommendations that have reduced the risk of chemical upsets at the wellhead and extended squeeze lifetimes downhole. However, as an increasing number of "problem wells," such as high crossflow wells, need to be treated to prevent scale formation, these models have to be adapted to enable them to capture the complex range of properties that make these systems so problematic. Diverter technology is being developed to enable optimal placement of chemical inhibitor, but to study the impact of the diverter on the squeeze performance, the fluid flow properties in the near-wellbore region must be modeled accurately. This is done by using a full-field reservoir simulation model that includes sufficient detail in the near-well formation not only to capture the fluid flows, but also to model accurately the chemical placement and recovery. The model can assess the impact of various placement strategies, as well as assist in determining the optimal fluid and chemical volumes. A case study from the North Sea where a gel diverter was selected to assist inhibitor placement is presented. The study demonstrates the types of calculation that can be made, and what information can be usefully supplied to the field engineer designing squeeze treatments. Introduction Mineral scale deposition in the near-wellbore area and tubular is a problem encountered in all types of production wells in the period following water breakthrough(1–3). Squeezing scale inhibitors into the near-wellbore formation is a strategy that has been used to successfully protect many hundreds of vertical wells(4–7). The squeeze treatment involves injection and over flush of a water-soluble chemical inhibitor that adsorbs onto the rock surface during a post-squeeze shut-in period. When the well is returned to production, the inhibitor slowly desorbs from the rock surface into the flowing water phase, and enters the well. Provided an appropriate choice of inhibitor is made, and provided it has been placed correctly, scaling tendencies in the produced water will be inhibited by the returning chemical for as long as its concentration remains above a threshold value(6,8). This Minimum Inhibitor Concentration (MIC) is routinely determined from laboratory Measurements(9). Modeling techniques have been developed to assist the design of squeeze treatments(10–14). Use of these models for optimizing treatments in vertical wells has proved very successful, and simulations are often performed as a matter of routine when designing treatments. However, the long production intervals associated with horizontal and deviated wells, along with the possibility of extended production at high water cuts, can make the design of squeeze treatments in these wells much more difficult. In addition, the increased capital investments and higher production rates associated with horizontal wells mean the risk of scale forming in the wellbore is even less tolerable than for conventional wells.

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“…Many examples of diversion materials and methods have been described in the literature (Erbstoesser 1980;Nitters and Davies 1989;Rossen 1996;Paccaloni 1995;Lietard 1997;Parlar et al 1995). These include but are not limited to…”

Section: Introductionmentioning

confidence: 99%

Fluid-Diversion Monitoring: The Key to Treatment Optimization

Glasbergen

Yeager

Reyes

et al. 2010

SPE Production &Amp; Operations

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In stimulation and injection treatments for removing or preventing formation damage, placement of the injected fluids is essential. Throughout the years, several diversion and placement techniques have been applied to obtain a desired fluid placement. A recent development is the application of distributed temperature sensing (DTS) to monitor the temperature profiles along the wellbore in real time during these treatments. Recent case histories showed that fluid placement can be quantified. Quantification of fluid distribution enables one to determine the flow distribution both before and after a diverter stage so that the diversion effect can be quantified.This paper discusses several case histories where DTS was applied to quantify the effectiveness of different diverters. The effects of chemical diverters, such as relative permeability modifiers (RPMs) and in-situ-crosslinked acids (ICAs), and moretraditional diverters, such as rock salt, are discussed. Because of the advanced monitoring used with the temperature profiles, both the immediate and the sustained effect of the diverters can be measured. The changes in the flow distribution are not limited to diverters. Reactive fluid or changes in flow rate can change the flow distribution as well. These effects were measured during the stimulation treatments.The post-treatment analysis of the measured temperature profiles in combination with treatment pressures and flow-rate information resulted in accurate knowledge of the effectiveness of the different diverters and stimulation effects over time. This knowledge will be used in future treatments to help optimize volumes, rates, fluid systems, and the selection of the appropriate diverter.

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A New, Effective Matrix Stimulation Diversion Technique

Cited by 53 publications

References 13 publications

Pore-Network Modeling of Carbonate Acidization

Pore-Network Modeling of Carbonate Acidization

Modelling Scale Inhibitor Squeeze Treatments in High Crossflow Horizontal Wells

Fluid-Diversion Monitoring: The Key to Treatment Optimization

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