The Feasibility of Fluorine Ammonium Compounds for Sandstone Formation Matrix Acidizing: Laboratory Study and Discussion

2013 ◽  
Vol 773 ◽  
pp. 628-633
Author(s):  
Fu Li ◽  
An Lin Wu ◽  
Min Min Xia ◽  
Hong Xian Liu ◽  
Ting Ting Zhang
Keyword(s):  
Acid System ◽  
Matrix Acidizing ◽  
Chemical Structures ◽  
Well Stimulation ◽  
Energy Needs ◽  
Ammonium Hydrogen ◽  
Lower Effect ◽  
Sandstone Formation ◽  
Great Possibility ◽  
Ammonium Compounds

As a preferred technology to enhance oilfield energy production, well stimulation has and will continue to have an important role in fulfilling the worlds future energy needs. Mud acid is a conventional acid system that reacts with most injurants and removes damages. However, fast reaction rate with minerals will lead to high leak-off velocity, great possibility of secondary and tertiary precipitation, lower effect of corrosion inhibitor in high temperature as well as short efficient operating range. Therefore, new kinds of acid system are required to cope with these problems above. This paper proposed three acid system with the similarity of fluorine ammonium compounds for sandstone acidizing ammonium hydrogen fluoride (AHF), ammonium fluotitanate (AFT), and ammonium fluoroborate system (AFB). Chemical structures, acidity test and solubility tests have proved the feasibility. Then, performance comparisons are conducted to prove the advantages over mud acid system.

A Matrix Acidizing System for Controlled Carbonate Well Stimulation using a Carboxylic Acid Salt with a Chelating Agent

2021 ◽  
Author(s):  
Albert Bokkers ◽  
Piter Brandenburg ◽  
Coert Van Lare ◽  
Cees Kooijman ◽  
Arjan Schutte
Keyword(s):  
Chelating Agent ◽  
Life Time ◽  
Nitrogen Atmosphere ◽  
Injection Rate ◽  
Sodium Gluconate ◽  
Matrix Acidizing ◽  
Well Stimulation ◽  
Stirred Reactor ◽  
Core Flood ◽  
Optimum Injection Rate

Abstract This work presents a matrix acidizing formulation which comprises a salt of monochloroacetic acid giving a delayed acidification and a chelating agent to prevent precipitation of a calcium salt. Results of dissolution capacity, core flood test and corrosion inhibition are presented and are compared to performance of 15 wt% emulsified HCl. Dissolution capacity tests were performed in a stirred reactor at atmospheric pressure using equimolar amounts of the crushed limestone and dolomites. Four different chelating agents were added to test the calcium ion sequestering power. Corrosion tests were executed using an autoclave reactor under nitrogen atmosphere at 10 barg. Core flood tests were performed to simulate carbonate matrix stimulation using limestone cores. It was found that the half-life time of the hydrolysis reaction is 77 min at a temperature of 100 °C. Sodium gluconate and the sodium salt of D-glucoheptonic acid were identified to successfully prevent the precipitation of the reaction product calcium glycolate at a temperature of 40 °C. Computed Tomography (CT) scans of the treated cores at optimum injection rate showed a single wormhole formed. At 150 °C an optimum injection rate of 1 ml/min was found which corresponds to a minimum PVBT of 6. In addition, no face dissolution was observed after coreflooding. Furthermore, the corrosion rates of different metallurgies (L80 and J55) were measured which are significantly less than data reported in literature for 15wt% emulsified HCl. The novelty of this formulation is that it slowly releases an organic acid in the well allowing deeper penetration in the formation and sodium gluconate prevents precipitation of the reaction product. The corrosivity of this formulation is relatively low saving maintenance costs to installations and pipe work. The active ingredient in the formulation is a solid, allowing onsite preparation of the acidizing fluid.

Experimental Evaluation of a New Nonaromatic Nonionic Surfactant for Deep Carbonate Stimulation

2021 ◽  
pp. 1-12
Author(s):  
Khatere Sokhanvarian ◽  
Cornell Stanciu ◽  
Jorge M. Fernandez ◽  
Ahmed Farid Ibrahim ◽  
Harish Kumar ◽  
...  
Keyword(s):  
Nonionic Surfactant ◽  
Pore Volume ◽  
Inductively Coupled Plasma ◽  
Oil And Gas ◽  
Low Cost ◽  
Acid System ◽  
Matrix Acidizing ◽  
High Corrosion ◽  
First Choice ◽  
The Stability

Summary Matrix acidizing improves productivity in oil and gas wells. Hydrochloric acid (HCl), because of its many advantages such as its effectiveness, availability, and low cost, has been a typical first-choice fluid for acidizing operations. However, HCl in high-pressure/high-temperature (HP/HT) wells can be problematic because of its high reactivity, resulting in face dissolution, high corrosion rates, and high corrosion inhibition costs. Several alternatives to HCl have been tested; among them, emulsified acid is a favorable choice because of its inherent low corrosion rate, deeper penetration into the reservoir, fewer asphaltene/sludge problems, and better acid distribution due to its higher viscosity. The success of the new system is dependent upon the stability of the emulsion, especially at high temperatures. The emulsified acid must be stable until it is properly placed, and it must also be compatible with other additives in an acidizing package. This study develops a stable, emulsified acid system at 300°F using aliphatic nonionic surfactants. This paper introduces a new nonaromatic, nonionic surfactant to form an emulsified acid for HP/HT wells. The type and quality of the emulsified acid were assessed through conductivity measurements and drop tests. The thermal stability of the system was monitored as a function of time through the use of pressure tubes and a preheated oil bath at 300°F. A LUMisizer® (LUM GmbH, Berlin, Germany) and Turbiscan® (Formulaction, S. A., L’Union, France) were used to determine the stability and the average droplet size of the emulsion, respectively. The viscosity of the emulsified acid was measured at different temperatures up to 300°F as a function of shear rate (1 to 1,000 s−1). The microscopy study was used to examine the shape and the distribution of acid droplets in diesel. Coreflood studies at low and high flow rates were conducted to determine the performance of the newly developed stable emulsified acid in creating wormholes in carbonate rocks. Inductively coupled plasma and computed tomography (CT) scans were used to determine the dissolved cations and wormhole propagation, respectively. Superior stimulation results with a low pore volume of acid to breakthrough (PVBT) were achieved at 300°F with the newly developed emulsified acid system. The wormhole propagation was narrow and dominant compared to branched wormholes resulting from conventional emulsified acid systems. Results indicate that a nonionic surfactant with optimal chemistry, such as a suitable hydrophobe chain length and structure, can form a stable emulsified acid. In this study we introduce a new and effective aliphatic nonionic surfactant to create a stable emulsified acid system for matrix acidizing at HP/HT conditions, leading to a deeper penetration of acid with low pore volume to breakthrough. The successful core flood studies in the laboratory using carbonate cores suggest that the new emulsified acid system may efficiently stimulate HP/HT carbonate reservoirs.

Study on a Self-Diverting Acid System for Well Stimulation Based on Novel Visco-Elastic Surfactant

2011 ◽  
Vol 287-290 ◽  
pp. 3120-3126 ◽  
Author(s):  
Fu Jian Zhou ◽  
Chun Ming Xiong ◽  
Yang Shi ◽  
Xian You Yang ◽  
Sheng Jiang Lian ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Carbonate Reservoir ◽  
Scanning System ◽  
Low Permeability ◽  
Acid System ◽  
Core Flooding ◽  
Well Stimulation ◽  
Core Permeability ◽  
Carbonate Formations ◽  
Oil Gas

Carbonate reservoir, widely distributed in china, is an important resource of oil and gas. Most of carbonate reservoir are very tight and need to be stimulated to increase the permeability for the flowing of oil/gas. Acid treatment is a kind of stimulation. However, the ordinary acid system cannot stimulate carbonate reservoir effectively because of the heterogeneity among formations. Based on a novel visco-elastic surfactant, this paper develops a self-diverting acid system (DCA) for carbonate formations. This system had been applied in the treatment of carbonate reservoirs successfully. Experiments studying the diverting mechanism had been conducted with HTHP Rheometer, parallel core flooding system and MRI Scanning system. The results indicate that: the viscosity of reacted acid can reach to 200 times higher than that of fresh acid. The injecting pressure of DCA is 20 times higher than that of ordinary acid (HCl) during the parallel core flooding experiment. MRI scanning images of the cores after acid flooding show that DCA can stimulate the cores with middle and low permeability more effectively. In middle and low permeability cores, the length of wormhole created by DCA is 4-8 times longer than that created by ordinary acid. At the same time, the relationship between flooding pressure and core permeability is also studied. This paper reveals the diverting mechanism of DCA through these experiments.

Addressing Matrix Acidizing Stimulation Challenges in Depleted, High-Temperature, and Acid-Sensitive Sandstone Formations with a High-Performance Acid System

2021 ◽  
Author(s):  
Rao Shafin Khan ◽  
Nestor Molero ◽  
Philippe Enkababian ◽  
Aizaz Khalid ◽  
Malik Anzar Afzal ◽  
...  
Keyword(s):  
High Temperature ◽  
Organic Acid ◽  
High Performance ◽  
Clay Content ◽  
High Energy ◽  
Acid System ◽  
Matrix Acidizing ◽  
Well Production ◽  
Production Trend ◽  
Sandstone Reservoirs

Abstract Acid stimulation in high-temperature sandstone reservoirs with high clay content can lead to undesired results due to secondary and tertiary reactions between treatment fluids and reservoir clays. Although there have been significant advancements in treating clastic formations over the years, high bottomhole temperature (BHT) coupled with high clay content of up to 35% and subhydrostatic conditions still presents a major challenge. A stimulation workflow to address these challenges was adapted to treat and successfully enhance well production in sandstone reservoirs in southern Pakistan. Candidate wells were selected for acidizing treatments based on declining production trend and identification of significant damage skin. X-ray diffraction tests on core samples indicated presence of acid-sensitive clays and calcite. Due to the risk of precipitation from secondary and tertiary reactions, conventional hydrochloric and hydrofluoric acid treatments were not viable options. Core flow testing was conducted to assess the efficiency of alternative acid systems at the reservoir conditions with BHT above 320°F, validating the selection of a high-performance sandstone acid system that was designed to handle undissolved clays in the critical matrix by helping to bind the clays to the pore surfaces, thus preventing them from migrating and plugging the pore throat during flowback. The matrix stimulation campaign included vertical and deviated dry gas wells, completed with 3 1/2-in. to 4 1/2-in. production tubing and 7-in. liner, with perforated intervals averaging 20 ft. Prior to the main acid treatment, high-pressure rotary jetting across the target intervals was conducted by pumping organic acid via coiled tubing. This wellbore conditioning technique allowed maximizing the acid performance by delivering 360° high-energy fluid to clear the perforations of scale and improve injectivity. The main treatment consisted of an organic acid preflush and a high-performance sandstone acid system as the main fluid, followed by a brine post-flush. Throughout the treatment, nitrogen was added to all fluids to facilitate fluid flowback under subhydrostatic conditions. The wells treated using this matrix stimulation engineered workflow yielded sustained production gains from 3 MMscf/D to 3.5 MMscf/D, exceeding expectations by more than 50% and achieving payback periods less than 20 days. The success of the treatment was largely due to the carefully designed stimulation workflow and its flawless execution. Acidizing high-temperature sandstone reservoirs with 30 to 35% clay content is uncommon. The experience gained in southern Pakistan validates the high-performance sandstone acid system as a reliable option for matrix acidizing in hot, acid-sensitive sandstone reservoirs. It also provides a detailed engineering workflow for candidate selection, treatment design, and job execution and evaluation, which can easily be adapted to regions facing similar challenges.

The Effect Of Matrix Acidizing On The Compressive Strength Of Sandstone Formation

2012 ◽  
Author(s):  
Ahmad Shamsul Izwan Ismail ◽  
Issham Ismail ◽  
Wilanin A/P Peng Buah ◽  
Ali Piroozian
Keyword(s):  
Compressive Strength ◽  
Room Temperature ◽  
Injection Pressure ◽  
Core Sample ◽  
Drilling Mud ◽  
Berea Sandstone ◽  
Matrix Acidizing ◽  
Hydraulic Equipment ◽  
The Matrix ◽  
Sandstone Formation

Artikel ini membincangkan kesan pengasidan matriks terhadap kekuatan mampatan sebuah formasi baru pasir. Kajian makmal terbabit melibatkan dua sistem utama, perkakasan pengasidan–kebolehtelapan dan kelengkapan hidraul servo. Asid lumpur dengan kepekatan HF 1–9% telah digunakan untuk merawat sampel teras batu pasir Berea yang rosak. Rawatan ini melibatkan tekanan suntikan dari 30 psi (206 KN/m2) hingga 660 psi (4550 KN/m2) pada suhu bilik. Sampel teras batu pasir Berea pada asalnya dirosakkan menerusi penggunaan lumpur gerudi sebelum bermulanya kerja–kerja pengasidan matriks. Selepas berakhirnya proses pengasidan, nilai kebolehtelapan tertingkat sampel teras yang telah dirawat menggunakan asid lumpur dibandingkan dengan kebolehtelapan rosak, yang diukur menggunakan perkakasan pengasidan–kebolehtelapan. Kekuatan mampatan formasi batu pasir selepas pengasidan juga dinilai menggunakan kelengkapan hidraul servo. Hasil kajian menunjukkan bahawa pengasidan berupaya meningkatkan kebolehtelapan sampel teras yang rosak, tetapi akan menjejaskan kekuatan mampatan sampel teras terbabit, lebih–lebih lagi jika menggunakan 9% HF–12% HCl. Isi padu asid lumpur yang digunakan untuk mencapai ARC 1.0 berkurang bila meningkatnya tekanan suntikan, tetapi tekanan terbabit mesti lebih besar daripada 30 psi (206 KN/m2) untuk mencapai nilai ARC yang lebih besar daripada 1.0. Tekanan suntikan yang terlalu tinggi boleh mengurangkan keberkesanan pengasidan secara menyeluruh berikutan masa tindak balas yang terhad. Kata kunci: Sampel teras batu pasir Berea; kekuatan mampatan; pengasidan matriks; kebolehtelapan This paper discusses the effect of matrix acidizing on the compressive strength of a sandstone formation. The laboratory works involved two main systems, namely the acidizing–permeability apparatus and servo hydraulic equipment. The mud acid with 1–9% HF concentrations was used to treat the damaged Berea sandstone core samples using different injection pressures ranging from 30 psi (206 KN/m2) to 660 psi (4550 KN/m2) at room temperature. The Berea sandstone core sample was initially damaged using drilling mud before the matrix acidizing took place. After the acidizing process, the value of improved permeability of the acidized core sample was compared with the damaged permeability, which was measured using the acidizing-permeability apparatus. The compressive strength of sandstone formation after the acidizing process was also evaluated using the Servo Hydraulic Equipment. The experimental results revealed that acidizing could improve the permeability of the damaged core sample but would affect the compressive strength of the core sample, especially when using 9% HF–12% HCl. The volume of mud acid required to achieve ARC 1.0 reduces when injection pressure increases, which should be greater than 30 psi (206 KN/m2) in order to achieve ARC greater than 1.0. It was also noted that higher injection pressure would reduce the overall effectiveness of the acid treatment due to insufficient reaction time. Key words: Berea sandstone core sample; compressive strength; matrix acidizing; permeability

Understanding Diversion with a Novel Fiber-Laden Acid System for Matrix Acidizing of Carbonate Formations

2010 ◽  
Author(s):  
Charles Edouard Cohen ◽  
Philippe Michel Jacques Tardy ◽  
Timothy Michael Lesko ◽  
Bruno H. Lecerf ◽  
Svetlana Pavlova ◽  
...  
Keyword(s):  
Acid System ◽  
Matrix Acidizing ◽  
Carbonate Formations

A Comprehensive Research to Find Suitable Acid for Sandstone Acidizing

2013 ◽  
Vol 787 ◽  
pp. 274-280 ◽  
Author(s):  
Mian Umer Shafiq ◽  
Aung Kyaw ◽  
Muhannad Talib Shuker
Keyword(s):  
Hydrochloric Acid ◽  
Hydrofluoric Acid ◽  
Orthophosphoric Acid ◽  
Color Change ◽  
Matrix Acidizing ◽  
Acid Formulation ◽  
Physical Interactions ◽  
The Common ◽  
Sandstone Formation ◽  
Selection Of

Stimulation of sandstone formations is a challenging task, which involves several chemicals and physical interactions of the acid with the formation. Some of these reactions may result in formation damage. Matrix acidizing may also be used to increase formation permeability in undamaged wells. Mud acid has been successfully used to stimulate sandstone reservoirs for a number of years. It is a mixture of hydrofluoric (HF) and hydrochloric (HCl) acids designed to dissolve clays and siliceous fines accumulated in the near-wellbore region. For any acidizing process, the selection of acid (Formulation and Concentration) and the design (Pre-flush, Main Acid, After-flush) is very important. Different researchers are using different combinations of acids with different concentrations to get the best results for acidization. Mainly the common practice is combination of Hydrochloric Acid and Hydrofluoric Acid with Concentration (3% HF 12% HCl). This paper presents the results of a laboratory investigation of orthophosphoric acid instead of hydrochloric acid in one combination and the second combination is fluoboric and formic acid and the third one is formic and hydrofluoric acid on undamaged low permeable sandstone formation. The results are compared with the mud acid and the results analyzed are permeability, color change and FESEM Analysis. All of these new combinations show that these have the potential to be used as acidizing acids in sandstone formations.

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