Summary Mud-acid treatments normally are designed by approximating the complex mineralogy of a sandstone with "lumping" procedure. Minerals are classified as either fast- or slow- reacting and the rates of their reaction with HF are determined by analysis of acid effluent from acidized core plugs. For most treatments carried out at modest temperatures and reasonable rates, this approach is satisfactory. In this paper, we show that at higher reaction temperatures, the simple two-mineral dissolution model does not apply because an intermediate product of the HF reaction with quartz, feldspars, and clays (H2SiF6) begins to react further with both clays and feldspars. This new reaction must be included to model data. The additional reaction, not observed at lower temperatures, has important consequences. For example, the acid injection rate is no longer critical. The analysis presented here shows that retarded acids are unnecessary. Contrary to previous concepts, mud acid itself provides a deep-penetrating capability. This surprising result may account for the high percentage of successful treatments even when this treatment is carried out under a wide range of conditions. Introduction Sandstone acidizing is a complex but widely applied and often successful well-stimulation process. A sandstone is an intricate composite of many minerals exhibiting a wide variety of morphologies. The HF reaction rate differs widely from mineral to mineral because of variations in the intrinsic reaction rates and the area of contact with the pore fluids. If the main reactions are rapid compared with the fluid flow rate (large Damkohler numbers), then a local equilibrium will apply and the process will be characterized by thermodynamic variables.1 In this case, the minerals initially present dissolve in a well-defined sequence while new minerals may precipitate. By this dissolution and precipitation process, zones of different mineral compositions develop and move through the porous medium at a rate strictly determined by the total number of PV's injected but independent of injection rate. At local equilibrium, Walsh et al.1 reported that an essential feature of even a well-designed sandstone treatment is the dissolution of aluminosilicates with the attendant precipitation of some form of monosilicic acid [Si(OH)4]. There are various possible forms of the precipitate, but here we call them silica gel. At the other extreme are the conditions for which at least some of the reactions are slow compared with the flow rate (small Dakohler numbers). Many models developed to represent the complexities of sandstone acidizing ignore those reactions, which lead to precipitation, and essentially consider only dissolution rates. The most widely used model divides the minerals that are found in sandstones into two categories-fast reacting (feldspars, authigenic clays, amorphous silica, etc.)2–5 This model, which is discussed in more detail here, has become known as the two-parameter model.2–4,6,7 There is little evidence defining the conditions where the rates of certain crucial reactions taken to be negligible in the two-parameter model begin to become significant. Recently, however, Bryant7 interpreted the failure of the two-parameter model to fit all three high-temperature core-plug acidizing experiments reported by Lindsey8 as an indication that the rates of certain reactions that appear at local equilibrium but are neglected in the two-parameter model now must be considered. The purpose of this paper is to examine Bryant's hypothesis and to define its practical implications. Reaction Kinetics The reactions for the slow- and fast-reacting minerals areEquation 1 and 2 The vk are stoichiometric coefficients. These reactions have been found to approximate first-order kinetics2,4,5 so that the following kinetic model is used:Equation 3 Where Cmin,k=concentration of accessible mineral k (an inaccessible mineral is not contacted by the pore fluids during the acidizing process2). We will show that this model fits the available data at low reaction temperatures where the reaction of the fluosilicic acid, H2SiF6, produced by Eqs. 1 and 2 with Mineral 1 is slow. At higher temperatures, reactions rates increase and the system tends to approach local equilibrium. The studies reported by Walsh et al.,1 which assumed local equilibrium, represent the limit of fast reactions. Walsh et al., found that large amounts of Si(OH)4 precipitate and, once formed, are difficult to remove by continued HF injection. In fact, for total acid volumes corresponding to those normally associated with acid treatments, this precipitate probably will remain in the near-wellbore region, and depending on where it is deposited in the pore structure (i.e., pore throats vs. pore bodies), it may be damaging. Thus, the issue is defined clearly. For higher temperatures (deep formations), H2SiF6 formed by the reaction of HF with Minerals 1 through 3 may itself react to a significant extent according toEquation 4 This reaction is a simplification of the comprehensive set of reactions that Walsh et al. Considered but is included in Bryant's model. Labrid,9 Shaughnessy and Kunze,10 and Crowe11 experimentally confirmed the existence of the reaction. The mechanism of fluosilicic acid reaction with clays or feldspars has not been studied, but considering it to be first-order seems reasonable. Thus, the rate of appearance of fluosilicic acid per unit volume is given byEquation 5 Note the Eqs. 1 and 2 produce fluosilic acid and must be included to obtain the net production rate.
Acidizing Gas Wells in the Merluza Field Using an Acetici Formic Acid Mixture and Foam Pigs Abstract This paper presents the laboratory testing of acid compositions and the planning, execution, and evaluation of the acidizing operations performed in the Merluza gas field, located offshore Brazil. Since the beginning of the production, the presence of calcium carbonate scale has been observed. Laboratory experiments determined that the most efficient acid mixture to remove that scale and to clean up perforations was 7% formic acid (HFor)/ 5% acetic acid (HAc) and that the best composition for matrix acidizing was saturated di-sodium EDTA. Regular HCl compositions were not recommended due to the nature of the tubing material (13Cr) and of the high reservoir temperature. The use of foam pigs to keep the acid at the desired position and to prevent the reaction products from decanting to the formation, and the application of the organic acid mixture to clean up the perforations were very successful, increasing the gas production rate by 740.000 m3/day. Because of this, the matrix acidizing with EDTA was postponed. These results show that Hac/H for compositions are a viable solution to acidize wells where HCl cannot be used, such as HPHT wells, or where production equipment contain chromium. P. 67
The productivity index of a horizontal well in an anisotropic medium is calculated during a process of partial acidization in which damage removal occurs only over a fraction of the length of the well. Two numerical simulators are used in this work: an acidizing simulator which calculates the permeability distribution around the wellbore and a reservoir simulator which calculates the productivity index of the well. By applying mathematical transformations, it was possible to reduce the acidizing model from a two-dimensional (2D) problem to a one-dimensional (lD) one. By comparing treatment results, it is possible to, select the optimal volume of acid, injection rate, and fraction of the length to be acidized for each particular well. The same procedure may also be applied for vertical wells both with and without anisotropy. Simulation results indicate that the application of a partial acidizing strategy reduces the total amount, of acid required for a significant improvement in well productivity. This may substantially reduce theinancial, operational, and environmental risks involved in the treatment of a horizontal well. In most cases, the optimal injection rate for sandstone acidizing is the maximum rate which does not fracture the formation. Introduction Matrix acidizing of vertical wells is a reasonably well understood technique and is generally modelled using a radial geometry. In recent years, however, the wide use of horizontal wells has required that the standard procedure for matrix acidizing be adapted to the new environment. Two major factors must be considered when designing an acid treatment for a horizontal well. First, the area exposed to the formation is much larger, due to the extended length of the wells. Second, the normally large contrast between the horizontal and vertical permeabilities must now be taken into account. Applying the conventional design procedure to a horizontal well would result in using huge amounts of acid and extremely long operations, with corrosion problems impossible to avoid using currently known corrosion inhibitors. It is, therefore, very important that a new technique be developed to acidize horizontal wells that reduces the total volume of acid to be used. The main objective of this work is to use numerical simulators in order to evaluate the feasibility of partially acidizing horizontal wells. Figure 1 illustrates this concept with the arrows showing the relative flow of fluids into the well after the acidizing is completed. An acceptable productivity increase can be obtained without having to inject an excessive amount of acid if only a fraction of the well length is treated. Issues such as the optimum volume of acid and optimum injection rate are addressed. Two criteria have been proposed for the injection rate: the maximum possible(1, 2) and an optimum rate that minimizes the acid volume(3, 4). Partial acidizing means to remove formation damage only in a few equally spaced intervals of the well, while the other segments remain untreated. FIGURE 1: Schematic of the partial acidizing concept. Illustrations available in full of paper. FIGURE 2: Schematic of the anisotropic problem. Illustrations available in full of paper.
Cement attack by acid during matrix acidizing operations has created severezonal isolation problems in wells with multiple adjacent permeable zones, operated by PETROBRAS. This effect was observed in several wells treated with conventional HCl-HF acid mixtures, even when cement bond logs prior to the acidjob were excellent. This paper presents a series of lab experiments showing that acetic acid, alone or mixed with HF, dissolves much less cement than HCl and HCl-HF mixtures with the same carbonate dissolving power. The reaction of acetic acid with cement forms a protective skin that inhibits further acid attack. The organic formulations were tested in an acidizing simulator, before being used in the field. The paper also presents field test results which confirmed that the acetic acid mixtures did not break zonal isolation (cement consumption was restrained to the perforated interval) and were able to generate 6- to 40-fold increases in the injectivity and productivity of the wells. Introduction Cement solubility in acids has been shown to be a problem, both in the field and by laboratory testing. Ref. 1 shows that HCl, HCl-HF, and citric acid have a strong detrimental effect on the cement, resulting in weight loss and compressive strength loss. Traditional views held that due to the formation of a protective skin, acid-cement reaction would be limited. However, severe zonal isolation problems have been observed, following HCl-HF treatments. The first approach to solve the problem was the development of acid-resistant cement. These blends use liquid latex that inhibits acid attack by coating cement particles and by reducing the permeability of the cement. Refs. 2 and 3 address the use of acid-resistant cement blends for primary cement and squeeze operations. This solution may be easily applied to new wells, in which the primary cement and squeeze jobs in front of the pay zones are composed of acid-resistant slurries.
The treatment of sandstone formations with mixtures of HF and HCI to remove formation damage is a widely practiced stimulation method; however, little attention normally is given to process optimization. This paper presents a procedure design that minimizes the total acid volume required to remove damage from a fixed-zone, near-wellbore region. To account for differences in formation mineralogy, a single laboratory coreflood experiment with field cores is necessary but more are recommended. The optimization method relies on scaling this experiment to a radial-flow geometry, where acid flux rates may differ substantially from those used in the single core test. Changing the injection rate is shown to result in a minimum acid volume at an optimum injection rate, and this optimum is found for a specific example.
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