An Alternative Solution to Sandstone Acidizing Using a Nonacid Based Fluid System With Fines-Migration Control
Abstract: fax 01-972-952-9435. AbstractThe Caballos formation is thick laminated sandstone with less than 10% of total clays and permeability ranging from 20 mD to as high as one Darcy. However, the production from this formation is often limited due to the low critical flow rate in the matrix (less than 1 mL/min) and associated fines migration as shown in several tests.Historically matrix acidizing and hydraulic fracturing treatments in this formation have only been partially successful due to destabilization of the cl… Show more
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Various methods have been employed mitigate fines migration problems that result in decreased productivity in oil and gas wells. This paper discusses the use of nanotechnology to fixate the migrating fines using the interaction between the migrateable fine particles present within the formation and nanoparticles associated with a proppant pack treatment. This paper will introduce the use of unique nanoparticles (nanocrystals) for treating hydraulic fracture proppant packs to fixate formation fines. Nanoparticle technology allows the combining of the extremely high surface area available using these particles, approximately 200 m2 /g, with the surface action of the material to fixate migrateable formation fines. Acting within the proppant bed, this fixation of the fines leads to more stable hydrocarbon inflow by reducing the rapid production decline often resulting from fines migration towards the wellbore. The nanoparticles can be added on-the-fly to hydraulic fracturing fluids to treat proppant just prior to being pumped downhole. The treated proppant pack will then capture and retain migrating fines, thereby preventing them from invading the pack and migrating towards the wellbore where flow impairment could occur. Laboratory developmental testing is presented to demonstrate the effectiveness of using this unique application of nanoparticle technology and field trials of this application should be completed by September, 2008. Introduction Formation fines are defined as loose or unconfined solid particles present in the pore spaces of sandstone formations and the particles are usually smaller than 37 microns, which means the particles small enough to pass through a 400 U.S. mesh screen.1~3 Formation fines include clay and non-clay particles, and charged as well as non-charged particles. These "fines" can be classified as detrital or authigenic in nature, meaning they were either originally deposited with the rock sediments or were created some time afterwards by weathering effects, respectively. It is formation fines in the authigenic category that usually cause most of the production problems by migrating to the wellbore and sometimes swelling. Examination of well cores with a scanning electron microscope is required to distinguish if the fines are likely to be the migrating variety. These particles may easily migrate with fluids that flow in sandstone formations. Reservoir fluid velocity increases tremendously as fluid moves from boundaries towards the wellbore. At a critical velocity near the wellbore fines can be picked up into the fluid or gas stream and redeposited near the wellbore. As well production continues, a large quantity of the formation fines can be concentrated in the near wellbore region. Continued fines migration and deposition near the wellbore can result in very high positive skin completions. If the fines migrate into a premium or prepacked screen, then localized plugging and high velocity "hotspots" could ensue, possibly resulting in screen erosion and failure. Different factors such as salinity, flow rates, pH, temperature, residual oil saturation, wettability, oil polarity and fractional flow of oil and water have been experimentally studied for their affects on the acceleration of formation fines migration.4~5 Many studies have been conducted in the industry to find ways to control migration of formation fines and to remove the concentrated formation fines in the near wellbore region. Several organic and inorganic clay control agents had been used to minimize fines migration in high-water-cut oil wells.6 Different acid systems were developed to remove the formation fines that plugged pores in the near wellbore region, gravel packs, and sand control screens for different downhole conditions.7~10
Various methods have been employed mitigate fines migration problems that result in decreased productivity in oil and gas wells. This paper discusses the use of nanotechnology to fixate the migrating fines using the interaction between the migrateable fine particles present within the formation and nanoparticles associated with a proppant pack treatment. This paper will introduce the use of unique nanoparticles (nanocrystals) for treating hydraulic fracture proppant packs to fixate formation fines. Nanoparticle technology allows the combining of the extremely high surface area available using these particles, approximately 200 m2 /g, with the surface action of the material to fixate migrateable formation fines. Acting within the proppant bed, this fixation of the fines leads to more stable hydrocarbon inflow by reducing the rapid production decline often resulting from fines migration towards the wellbore. The nanoparticles can be added on-the-fly to hydraulic fracturing fluids to treat proppant just prior to being pumped downhole. The treated proppant pack will then capture and retain migrating fines, thereby preventing them from invading the pack and migrating towards the wellbore where flow impairment could occur. Laboratory developmental testing is presented to demonstrate the effectiveness of using this unique application of nanoparticle technology and field trials of this application should be completed by September, 2008. Introduction Formation fines are defined as loose or unconfined solid particles present in the pore spaces of sandstone formations and the particles are usually smaller than 37 microns, which means the particles small enough to pass through a 400 U.S. mesh screen.1~3 Formation fines include clay and non-clay particles, and charged as well as non-charged particles. These "fines" can be classified as detrital or authigenic in nature, meaning they were either originally deposited with the rock sediments or were created some time afterwards by weathering effects, respectively. It is formation fines in the authigenic category that usually cause most of the production problems by migrating to the wellbore and sometimes swelling. Examination of well cores with a scanning electron microscope is required to distinguish if the fines are likely to be the migrating variety. These particles may easily migrate with fluids that flow in sandstone formations. Reservoir fluid velocity increases tremendously as fluid moves from boundaries towards the wellbore. At a critical velocity near the wellbore fines can be picked up into the fluid or gas stream and redeposited near the wellbore. As well production continues, a large quantity of the formation fines can be concentrated in the near wellbore region. Continued fines migration and deposition near the wellbore can result in very high positive skin completions. If the fines migrate into a premium or prepacked screen, then localized plugging and high velocity "hotspots" could ensue, possibly resulting in screen erosion and failure. Different factors such as salinity, flow rates, pH, temperature, residual oil saturation, wettability, oil polarity and fractional flow of oil and water have been experimentally studied for their affects on the acceleration of formation fines migration.4~5 Many studies have been conducted in the industry to find ways to control migration of formation fines and to remove the concentrated formation fines in the near wellbore region. Several organic and inorganic clay control agents had been used to minimize fines migration in high-water-cut oil wells.6 Different acid systems were developed to remove the formation fines that plugged pores in the near wellbore region, gravel packs, and sand control screens for different downhole conditions.7~10
Stimulation in Wells with Electric Submergible Pumps Increases Production and Save Costs without Damaging Pumps
Stimulating sandstone formations typically requires a mixture of hydrochloric acid (HCl) and hydrofluoric acid (HF) to dissolve formation damaging minerals. The HF reacts with and dissolves all HCl soluble minerals and, dissolves or partially dissolves siliceous materials such as bentonite and naturally occurring formation clays. Because these acid treatments are corrosive, it is common practice in low-pressure wells to pull out the electrical submersible pumps (ESPs) prior to performing a stimulation treatment to prevent damage to them. Doing so results in additional costs and deferred production.In Ecuador, oil is produced from low-pressure sandstone reservoirs by using ESPs. In many of these reservoirs production is limited by scaling or fines migration. The low reservoir pressure often results in additional formation damage when during workovers because of the loss of completion fluid, emulsions, and clay instability. Many operators prefer to produce well with formation damage rather than expose the ESPs to corrosive fluids to remove the damage or generate additionally damage during a workover.Using a non-acid chelating system (NACS) as the stimulation fluid combined with a placement technique made it possible to stimulate wells completed with ESPs or with corrosion sensitive completions, without needing to pull out the ESP for the stimulation treatment.A laboratory study to assess the corrosion of each component of an ESP exposed to different treating fluids (live and spent) for extended periods was undertaken. The NACS fluid was capable of both removing calcium scales and fines, and preventing fines migration while minimizng corrsoion.The NACS stimulation fluid successfully treated more than 10 wells competed with ESPs. In many cases, production in these wells increased by 35%. In addition, the treatment cost was 70% less than treatments for which a workover rig was used. Moreover, deferred production was reduced from days to hours.Because of the time and cost savings, this technique should be particularly beneficial in marginal fields, where rig availability and economics are often an issue.
Developments in Sandstone HF Acidizing: HF Fluid Compatible with Na or K Brines and Carbonate-Laden Mineralogy for High Temperatures (360°F)
Using hydrofluoric (HF) acid for the removal of clays and silica minerals impairing permeability in sandstone formations requires fluids free of sodium or potassium ions. High temperatures (> 300°F) further limit HF acid use and its effectiveness because of potentially damaging effects to the formation and its corrosivity. This paper discusses laboratory testing of an aminopolycarboxylic acid (APCA) fluid containing 1 to 1.5% HF acid and highlights its advantages and differentiating characteristics with respect to previous HF acid fluids. Core flow testing at 360°F was conducted on outcrops of two types of sandstone representing a heterogeneous (65% quartz and illite/kaolinite with feldspars) and a clean (95% quartz) type of mineralogy. The APCA fluid containing HF acid, which incorporates a modulating agent for the HF acid-secondary reaction on aluminosilicate minerals, was compared to the pure APCA (pH 2) fluid and formic acid. Effluent analysis of the spent fluid was completed by inductively coupled plasma (ICP) optical emission spectroscopy (OES). Corrosion inhibition testing was completed for coiled tubing (CT) and carbon steel (NT-95) up to 360°F, employing various classes of inhibitors. Using an APCA chelating agent in sandstone HF acidizing expands the temperature range of application and the type of minerals that can be exposed to such fluid. High-temperature HF acidizing is also delimited by the type of steel tubing that can be exposed to such fluid, placing significant demands on corrosion control. Laboratory results obtained in this investigation demonstrate that corrosion can be well managed for a fluid having a pH of 2.5 and HF acid concentrations of 1 to 2% from 250 to 275°F and at 300°F with a pH of 4. Testing results show that the APCA/HF fluid, having a pH of 2.5, can effectively be used to treat heterogeneous sandstone of moderate carbonate content at 360°F and is also compatible with a clean sandstone. The APCA/HF fluid stabilizes the most problematic ions in the spent fluid—Al3+, Fe2+/3+, Ca2+, and alumino-fluorides—without the need for acid preflushes and without maintaining highly acidic conditions. Comparison to formic acid and HF acid-free APCA fluid is presented. Using aminopolycarboxylic acid-type chelants is restricted by the materials commercially available, all of which contain sodium, with one exception, which has ammonium. Hence, HF acidizing has been restricted to ammonium-containing fluids. A differentiating characteristic of the fluid reported here is its ability to sustain Na+ concentrations exceeding 1 M and K+ concentrations in excess of 0.5 M. Furthermore, it is suitable for the treatment of carbonate-laden mineralogy formations up to 360°F.
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