High-Temperature Laboratory Testing of Illitic Sandstone Outcrop Cores With HCl-Alternative Fluids

Mahmoud, Mohamed; Nasr‐El‐Din, Hisham A.; Wolf, Corine A. de

doi:10.2118/147395-pa

Cited by 24 publications

(17 citation statements)

References 17 publications

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“…The iron can be chelated from chlorite mineral, calcium from calcite and dolomite, magnesium can be chelated from dolomite, and aluminum can be chelated from clay minerals such as illite and kaolinite. Both EDTA and HEDTA are compatible with Berea sandstone cores, and no fines were observed in the collected effluent samples (Mahmoud et al 2015;2011). Figure 3 shows the effect of using HEIDA chelating agent on sulfate scale precipitation and on the enhancement of core permeability.…”

Section: Resultsmentioning

confidence: 99%

Using high- and low-salinity seawater injection to maintain the oil reservoir pressure without damage

Mahmoud

Elkatatny

Abdelgawad

2016

J Petrol Explor Prod Technol

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The oil reservoir pressure declines due to oil production, and this decline will lead to reduction in the oil productivity. The reservoir pressure maintenance is a practice in the oil industry in which seawater is injected into the aquifer zone below the oil zone to support the reservoir pressure. Calcium sulfate scale is one of the most serious oilfield problems that could be formed in sandstone and carbonate reservoirs. Calcium sulfate may precipitate during the injection of seawater with high sulfate content into formation brine with high calcium content. Mixing seawater and formation water may cause precipitation of calcium sulfate, barium sulfate, and/or strontium sulfate. Seawater treatment does not remove the entire sulfate ions from the injected water. Low sulfate concentrations may cause damage. Enhanced oil recovery processes such as smart water injection, which originally is diluted seawater, may cause calcium sulfate precipitation as the reduction of water salinity will increase the sulfate precipitation and decrease its solubility. This study was conducted to investigate the damage caused by the deposition of calcium sulfate precipitation. A solution is proposed to prevent the damage due to calcium sulfate by using chelating agents. Several coreflooding experiments were conducted using Berea sandstone and Indiana limestone cores at reservoir conditions of pressure and temperature using seawater (high and low salinity) and formation water. Chelating agents used in this study are: EDTA (ethylenediaminetetraacetic acid), HEDTA (hydroxyethylenediaminetriacetic acid), and HEIDA (hydroxyethyliminodiacetic acid). HEDTA and HEIDA chelating gents are environmentally friendly and can be used in marine environment. High-salinity water injection caused severe formation damage, and the injectivity will decline faster compared to the low-salinity water injection. HEDTA and EDTA chelating agents at low concentrations performed better than HEIDA chelating agents in both Berea sandstone and Indiana limestone cores. HEDTA and EDTA chelating agents were able to prevent the damage due to calcium sulfate precipitation and enhanced the core permeability.

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Section: Resultsmentioning

confidence: 99%

Using high- and low-salinity seawater injection to maintain the oil reservoir pressure without damage

Mahmoud

Elkatatny

Abdelgawad

2016

J Petrol Explor Prod Technol

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“…A lingering issue surrounding this premise is the degree of effectiveness that a given APCA can have for Ca 2ϩ in the pH range of 0 to 3, which is the pH range where the most acidic proton of an APCA will undergo dissociation and generate a binding (stabilizing) site (the carboxylate ion) . Previous work with GLDA/HF from other researchers has already indicated that CaF 2 precipitation is to be expected (Mahmoud et al 2014) even when using the fluid at a pH of 3.8, which, in principle and in the absence of competing equilibria, should provide improved complexation of Ca 2ϩ . The conclusion reached by Mahmoud et al (2014) is that, to minimize the negative effects associated with free fluoride (F -), the concentration of HF should not exceed 1% when using NaH 3 GLDA.…”

Section: Problem Frameworkmentioning

confidence: 98%

“…Previous work with GLDA/HF from other researchers has already indicated that CaF 2 precipitation is to be expected (Mahmoud et al 2014) even when using the fluid at a pH of 3.8, which, in principle and in the absence of competing equilibria, should provide improved complexation of Ca 2ϩ . The conclusion reached by Mahmoud et al (2014) is that, to minimize the negative effects associated with free fluoride (F -), the concentration of HF should not exceed 1% when using NaH 3 GLDA. Notably, this conclusion appears to emanate from work centered on other APCA, such as EDTA and HEDTA, which are not as soluble as GLDA in pH lower than 3.…”

Section: Problem Frameworkmentioning

confidence: 98%

“…One of the potential problems associated with the use of HF in situations where there is calcium, naturally present or artificially introduced, is the formation and precipitation of CaF 2 . The single approach to circumvent this problem is to avoid the use of HF altogether, or minimize the concentration of HF to 1% w/v (Frenier et al 2004;Mahmoud et al 2014;Reyes et al 2013b). Otherwise, extensive preflush stages of acid and NH 4 Cl are necessary (Jiang et al 2004).…”

Section: Introductionmentioning

confidence: 99%

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GLDA/HF Facilitates High Temperature Acidizing and Coiled Tubing Corrosion Inhibition

et al. 2015

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An existing limitation of chelant-based fluids available for sandstone acidizing with hydrofluoric acid (HF) is the presence of sodium in the concentrate of the aminopolycarboxylate fluid, which is common in all chelating agents soluble below pH 3.5. The presence of sodium complicates stabilization of the fluid during acidizing processes because of the myriad of chemical reactions that can impact the outcome of a treatment. The use of chelating agents has expanded the temperature range as well as the type of clay minerals that can be exposed to an HF fluid; however, limitations still exist. Core flow testing at 360°F and corrosion testing from 265 to 360°F were conducted. Flow tests were performed using outcrops of two types of sandstones and inductively coupled plasma (ICP) analysis was conducted to elucidate the ionic composition of the spent fluid. Results reported stem from core flow testing with glutamic acid diacetic acid (GLDA) containing HF at very high temperatures (360°F). To encompass a broad range of mineral composition, two types of sandstone cores were employed-heterogeneous (Bandera, 65% quartz) and clean (Leopard, 95% quartz). Corrosion inhibition of the GLDA/HF fluid for use with coiled tubing (CT) was achieved up to 320°F, employing varying classes of inhibitors. The GLDA/HF fluid exhibited lessened corrosion tendencies and could be inhibited for at least 6 hours at 360°F for drillpipe (mass loss rates of 0.025 to 0.05 in./ft 2 were obtained).The presence of sodium in GLDA/HF could be managed, leading to effective permeability improvement of the Bandera core, while the Leopard core underwent a decrease in overall permeability; this latter observation was attributed to the formation of metal fluorides. Neither the presence of CaCO 3 in the Bandera substrate or the use of KCl brine substituting for the usual NH 4 Cl led to permeability impairment. The overall results indicated that 1% HF and 0.6 M GLDA with an auxiliary agent could circumvent the expected problems associated with HF acidizing and modification, volume minimization, or elimination of preflushes. The use of the GLDA chelant facilitates, when using CT to deliver fluid to hot zones (which can be susceptible to formation damage if aggressive fluids based on HCl or formic acid are used, or if acetic acid is employed), could be jeopardized because of the difficulties inhibiting the corrosive effects of HF, HCl, formic, or acetic blends.

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“…They were followed by Frenier and co-workers (2001Frenier and co-workers ( , 2003Frenier and co-workers ( , 2004 who introduced HEDTA. Mahmoud et al used GLDA to stimulate carbonate (LePage et al 2011;Mahmoud et al 2011aMahmoud et al , 2011b and sandstone formations (Mahmoud et al 2015) to remove carbonates and oxides minerals. Reyes et al (2013) examined a new chelant.…”

Section: Introductionmentioning

confidence: 99%

Evaluation of Methods to Improve Matrix Stimulation of Horizontal Carbonate Wellbores

Nasr‐El‐Din

Shedd²,

Germack³

et al. 2015

Day 2 Tue, November 10, 2015

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Acid stimulation of horizontal wellbores in high temperature and/or low permeability formations is complicated due to the need to balance acid reaction rates with the rate of formation penetration. At high bottom hole temperatures, uncontrolled acid spending rates result in inefficient or even damaging treatments. It is advantageous to add materials which slow the reaction of HCl or use alternative acids which are useful as alternative stimulation fluids, such as organic acids and chelants due to their inherently lower reaction rates. The slower reaction rate with carbonate minerals allows for optimal wormhole growth at the limited rates available in long horizontals. This study investigates the complementary use of acid or chelant systems together with a microemulsion delivery system to achieve the desired performance. These delivery systems can significantly increase the efficiency of HCl and chelant stimulation treatments of low-permeability carbonates by optimizing diffusivity and minimizing pressure to cleanup.Horizontal core flow experiments were conducted by injecting solutions of 15 wt% HCl and 10 -20 wt% alternative acids through low permeability (Ͻ 10 md) limestone cores. High permeability cores were also investigated by injecting 15 wt% HCl through high permeability (150 -200 md) Indiana limestone cores. These experiments were conducted with and without the addition of a microemulsion additive and at core injection rates from 0.2 -20 cm 3 /min corresponding to 0.25 to 5 BPM per 100 ft of a horizontal wellbore.Significant performance advantages were found with the addition of the microemulsion delivery system. The treatment volume required for wormholes to propagate the length of the test core was reduced at all flow rates at or above the optimum rate. Core penetration was more efficient when using the microemulsion, without an increase in pumping pressure. Initiation and extension of wormholes was improved, as compared to the experiments without the microemulsion, in which more conical wormholes tended to form at the inlet face. The reduction in treatment volume necessary to reach breakthrough with the microemulsion present also suggested a more efficient treatment.The complementary use of a microemulsion delivery system with acids and chelants has been shown to enhance acid stimulation treatment potential in long horizontal wellbores with high temperature or low permeability formations. This system can be used to optimize wormhole penetration while maintaining an optimum injection rate across long horizontal intervals where the maximum achievable injection rate is relatively low.

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High-Temperature Laboratory Testing of Illitic Sandstone Outcrop Cores With HCl-Alternative Fluids

Cited by 24 publications

References 17 publications

Using high- and low-salinity seawater injection to maintain the oil reservoir pressure without damage

Using high- and low-salinity seawater injection to maintain the oil reservoir pressure without damage

GLDA/HF Facilitates High Temperature Acidizing and Coiled Tubing Corrosion Inhibition

Evaluation of Methods to Improve Matrix Stimulation of Horizontal Carbonate Wellbores

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