ARTICLE pubs.acs.org/EF
Integrated Approach to Acid Treatment Optimization in Carbonate Reservoirs Rinat Ya. Kharisov,† Aleksey E. Folomeev,† Andrey R. Sharifullin,† Guzel T. Bulgakova,*,‡ and Aleksey G. Telin† † ‡
RN-UfaNIPIneft Ltd., Rosneft Oil Company OJSC, 96/2, Revolutsionnaya Street, Ufa 450078, Russia Ufa State Aviation Technical University, 12, Karl Marx Street, Ufa 450000, Russia ABSTRACT: This paper describes an integrated approach to stimulation treatment design for carbonate reservoirs. When given a choice in the technology of well acid stimulation in a carbonate reservoir, the use of an integrated approach to reagent selection and treatment design is necessary. Accounting for the properties of acidic compounds for specific geological and physical conditions increases the efficiency of the well bottom zone stimulation because of a larger radius of influence, which prevents the formation of insoluble compounds and bridges the pore space of this zone. Results of the determination of the kinetic parameters and characterizations of the rate of the acid composition reaction with oil- and water-saturated rock samples are given.
’ INTRODUCTION Acid stimulation is the main method of oil production enhancement in carbonate reservoirs13 and typically involves an application of an acid composition based on hydrochloric acid. The objectives of carbonate formation acidizing include permeability and reservoir stimulation by the formation of highpermeability channels (“wormholes”).4 The efficiency of this method depends upon the depth of active acid penetration into formations and the completeness of rock dissolution. One of the main challenges in predicting the effectiveness of a carbonate stimulation treatment is accounting for the wide range of dissolution structures that can be formed and their impact on skin evolution. The structure of the dissolution channel is highly dependent upon the injection rate and fluid/mineral properties. The main types of dissolution structures include (i) face dissolution, (ii) conical wormholes, (iii) dominant wormholes (long, narrow, relatively unbranched wormholes, representing optimum), (iv) ramified wormholes, and (v) uniform dissolution. Examples of these dissolution structures are shown in Figure 1. The first four images are neutron radiographs of dissolution structures formed during the dissolution of calcite.4,5 The fifth image is a Wood’s metal casting of a dissolution structure formed during the dissolution of dolomite.6 The transition of dissolution structures from left to right is commonly observed as the injection rate is increased. At low injection rates (far left structure), the reactant is consumed on the inlet flow face of the core, which results in complete dissolution of the core starting from the inlet flow face. At slightly higher injection rates, the reactant can penetrate into the porous matrix and enlarge the flow channels. However, a significant amount of reactant is consumed on the walls of the flow channels, resulting in the formation of a conical-shaped dissolution channel. At intermediate injection rates, the reactant is transported to the tip of the evolving flow channel, where subsequent consumption propagates the channel and eventually leads to the formation of a dominant wormhole. At high injection rates, the dissolution channels become more highly branched or ramified as fluid is forced into smaller pores. In the r 2011 American Chemical Society
extreme cases of a high injection rate or low reactivity (far right structure), uniform dissolution is observed as the reactant is transported to most of the pores in the medium. Under the appropriate conditions, the non-uniform acid velocity field created by local formation heterogeneities leads to uneven rock dissolution and the formation of dissolution channels that may extend deep into the rock matrix. The structures of these dissolution channels have been experimentally observed to depend upon the operating conditions, including the temperature, acid injection rate, formation properties, and reactant properties. The dissolution structures range from deep-penetrating wormholes that effectively bypass formation damage to the compact dissolution of the wellbore wall that results in nothing more than an increase in the wellbore radius. For a carbonate matrix stimulation treatment to be successful, it is important to acidize under conditions that will lead to the formation of deep-penetrating wormholes using minimal acid volumes. The skin value s has been calculated for a stimulated (or damaged) area around the wellbore with radius rs and permeability ks, using Hawkins formula7
k rs s¼ 1 ln ks rw
ð1Þ
where k is the permeability and rw is the wellbore radius. The core flow shows that wormholes formed with plain HCl have an almost infinite permeability. If ks . k, the ratio k/ks drops out of eq 1 and the skin value only depends upon the wormhole penetration depth rs. This means that narrow but deeply penetrating wormholes are to be preferred above wide but short wormholes. Special Issue: 12th International Conference on Petroleum Phase Behavior and Fouling Received: September 14, 2011 Revised: November 20, 2011 Published: November 22, 2011 2621
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Figure 1. Dissolution structures observed in linear core tests.
Numerous carbonate dissolution models have been developed over the past 30 years to determine the optimum conditions for wormhole formation and to determine the rate of wormhole growth.817 The models of wormhole formation and the conditions under which the models apply have been reviewed elsewhere.18 The technical limitations for each model are also discussed. The research of Fredd and Fogler4,5,11,12 demonstrated that the phenomenon of wormhole formation is governed by the Damk€ohler number for all fluid/mineral systems investigated. The general definition of the Damk€ohler number is the ratio of the net rate of dissolution to the rate of transport by convection. Because only one high-conductive channel is formed during experiments on the core, the convectiondiffusion task for the acid concentration in the cylindrical pore channel was defined in ref 12. Using dimensionless parameters for the task, the Damk€ohler number, Da, was defined as Da = πdLk/q, where q is the flow rate in the wormhole, d and L are the diameter and length of the wormhole, respectively, and k is the overall dissolution rate constant. The Damk€ohler number dictates the type of wormhole structures that are formed by systems with various degrees of transport and reaction limitations. More importantly, there exists an optimum Damk€ohler number at which dominant wormhole channels are formed and the number of pore volumes required to breakthrough is minimized. This optimum Damk€ohler number occurs at approximately 0.29 for a wide range of fluid/mineral systems investigated in linear core flood experiments. Upgrades in technology have allowed for increased acidizing efficiency with reagents of various compositions that slow and cause front deviation of the acid reaction with the carbonate rock matrix (emulsions, polymers, surfactants, cross-linked polymers, foam systems, and finely dispersed additives). Acid compositions that contain chemical additives must provide the maximum depth of active reagent penetration into formations and comply with specific reservoir conditions. This approach allows for room to increase the acid treatment efficiency and to avoid negative consequences caused by acid composition and reservoir fluid incompatibility, e.g., the formation of stable emulsions and insoluble sediments, which lead to the secondary colmatation of a wellbore area. If acidizing is planned for carbonate formation stimulation, selection of the appropriate reagents should be based on an integrated approach. Inhibiting acidrock interactions can increase the depth of reagent penetration into formations. Key parameters that provide inhibition of the acid interaction process can be adjusted to slow the acid diffusion
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rate in rock, to reduce the hydrogen ion concentration (H+) in a solution, and to form a protective sorption layer on the rock surface. The main factors that influence the above-listed parameters are the acid concentration and volume, physical and chemical properties, temperature, pressure, rock chemical composition, reservoir structure, acid injection rate, and active additives. One of the most popular and effective ways of inhibiting acidrock interactions is related to the selection of specific additives for the acid reagent. The composition should be based on preliminary laboratory tests using rock samples. For this purpose, we conducted a series of experiments for selecting the optimum acidiferous compositions, in which those that reacted with water-saturated rocks more slowly than with oil-saturated rocks and those that provided the maximum depth of technological fluid penetration into the formation were desired. The selection of reagents was based on an investigation of the kinetics of reactions between the acidferous compositions and the water- and oil-saturated rocks. The CO2 volume released over a certain period of time during core acidizing under the formation temperature was estimated. This technique is different from other methods because it consists of using excess acid and reacting disintegrated rock saturated with either oil or water. This experiment allows for better consideration of the wettability, hydrophobization, and hydrophilization of the pore surfaces. Moreover, the use of cores and oil from specific reservoirs in the experiments increases the accuracy of the physicochemical modeling of the processes in the near-wellbore zone. The conducted physicochemical experiments provided kinetic parameters of the acid compositions that influence the carbonate rock dissolution rates. The results showed that the acid composition effect is essentially controlled by the rock wettability: the use of a surfactant allows for the reagent to partially impact the waterand oil-saturated pore structure of the carbonate rocks. The examined acid compositions increased this effect on the nearwellbore zone, reduced corrosion attack on the production casing, tubing, and wellhead equipment, and prevented the deposition of insoluble particles and the clogging of the pore space in the near-wellbore zone. The application of strong inorganic acids (hydrochloric acid) was not effective for stimulating wells with high-temperature carbonate reservoirs. For the stimulation of such wells, we examined reagents that generate acid under the reservoir conditions (organic acid esters and alumochlorides) and reagents with non-acid character that can dissolve carbonate rock (chelating compounds). The obtained kinetic parameters were used in a mathematical model to simulate the acid treatment process in carbonate reservoirs for the purpose of optimizing the acid treatment. The following paragraphs will focus on the main stages of the carbonate stimulation optimization.
’ OPTIMAL CANDIDATE SELECTION FOR ACIDIZING Although acidizing methods have a history more than a century long2 and have played a significant role in stimulating oil and gas recovery, they often pose quite challenging and ambiguous problems because of their diversity and variable properties and the estimated efficiencies of production wells and resource constraints. The drilling of oil wells begins only after an analysis of information based on geology and geophysics generated by exploratory research in the prospecting stage has been performed. An integrated approach to stimulation treatment design for carbonate reservoirs helps to ensure 2622
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Figure 2. Simplified view of petroleum.19 that appropriate candidates are stimulated with the optimum treatments. The preliminary candidate selection is based on estimated productivity gains from various stimulation options. The candidate selection for stimulation is part of the field-development decision process. The wise use of available budget funds for well treatment requires the selection of wells with the greatest potential to improve both short-term productivity and long-term reservoir management and recovery.19 Effective stimulation candidate selection is the process of ensuring that the appropriate treatments are matched with the appropriate wells. The goal of this process is a prioritized list of stimulation candidates that has been narrowed from many to the crucial few. This process involves both sorting and ranking: sorting in the sense that different wells (or intervals in wells) require different treatment solutions, such as matrix acidizing, acid fracturing, proppant fracturing, and reperforating, and ranking all of the matrix acidizing candidates, so that those with the highest potential for productivity improvement are given top priority.
’ CHEMICAL TESTS OF TREATMENT-AGENT FLUIDS FOR CARBONATE ACIDIZING Testing the Compatibility of Acid Compositions with Reservoir Oil. A complex analysis of acid compositions used or
found eligible in treatments is an integral part of acidizing operations. One of the issues that emerges is the chemical incompatibility of the acidizing agents with the reservoir fluids, which results in acidoil emulsions and asphaltene dropout. The formation of stable acidoil emulsions in the treated reservoir is manifested in a non-uniform manner. Thus, in terrigenous reservoirs, the emerging emulsion thwarts acid wormholing, clogging the channels because of a rapid viscosity buildup. In carbonates, this phenomenon is considered beneficial and results in acid diversion because of matrix dissolution. However, the emulsion has to be disposed of afterward to avoid further problems that are likely to occur during oil treatment. Emulsion stability is largely affected by the reservoir oil composition. In particular, the presence of asphaltenes and resins contributes to the generation and stabilization of acidoil emulsions. Some anomalous oils may contain up to 30% resins.20 From a chemical point of view, petroleum is a very complex dispersed system. The structural core of petroleum is generally considered to be similar to asphaltene/resin compositions, with resins as the solvation shell and lighter fractions as the dispersed phase (Figure 2).20 The term “asphaltenes” was first coined in 1837 by J. B. Boussingault in reference to a bitumen residuum that was insoluble in alcohol but soluble in excess turpentine.21 Asphaltenes are arbitrarily defined as a solubility class of petroleum that is insoluble in light alkanes but soluble in toluene or dichloromethane.20,2224 Asphaltenes are prone to association
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with supermolecular structures that emerge in the form of a stack of flat molecules, with an intermolecular distance of about 0.4 nm. The presence of asphaltenes in reservoir oil does not presuppose any adverse consequences during production. Heavier petroleum components with maximum asphaltene concentrations will normally remain stable and cause no wellbore contamination or blockage. The bulk of the problems associated with asphaltene deposition is peculiar to lower viscosity oils.21 The Vankor field reservoir oils provide an interesting example. The reservoir oil of the Lower Hittite formation sequence (Nh-1) is characterized by low viscosity (2.4 mPa s at reservoir temperature Tres) and produces asphaltenes when mixed with mud acid (12% HCl/3% HF acid solution). However, the high-viscosity oil of the Yakovlev sequence Yak 3-7 (32.25 mPa s at Tres) does not produce asphaltenes when mixed with mud acid. Asphaltenes are often assumed to not dissolve in petroleum but rather to be dispersed/suspended in the fluid as colloids (evidence of this is controversial). The amount, chemical constituency, and physical structure of the precipitated asphaltenes vary with precipitant type, pressure, and temperature (Figure 3).20 Pure asphaltenes are black, dry powders and are nonvolatile; they tend to crack before boiling (Figure 4). The precipitation of asphaltenes from oil occurs during acidizing under the influence of the hydroxonium ion (H3O+), which destabilizes the asphalteneresin system and causes asphaltene association (Figure 5). A mathematical model for asphaltene deposition that is based on the transport of stable particulate suspensions in porous media was developed and validated directly with experimental results and data found in the literature.26 On the basis of the developed mathematical model, two distinct mechanisms were identified as a consequence of the deposition process, namely, asphaltene adsorption and trapping. The porous medium was represented as a network of sites and bonds, with pore bodies identified as the sites and pore throats identified as the bonds. A satisfactory qualitative agreement was observed with the experimental results.26 The asphaltene sludge precipitated because of the presence of FeIII ions in the acid solution (Fe3+) that spawn ferrous asphaltene associates.25 Therefore, if the acid solution is weakly ferro-stabilizing, there is a double risk of colmatation (clogging) of the pore volume by colloidal FeIII hydroxide [Fe(OH)3] and deposition of ferrous asphaltene associates. To counteract these consequences, iron stabilizers (sequestering agents) are used to convert Fe3+ ions into Fe2+ ions or to produce soluble ferrous compositions, thereby preventing deposition of FeIII hydroxide and ferrous asphaltene associates. Reservoir oil is susceptible to sludging at high reservoir temperatures even when low acid concentrations cause the precipitation of a crystalline sediment. The Praskoveyskoye (reservoir temperature Tres = 146 °C), Ozek-Suat, and Pushkarskoye (Tres = 135 °C) oil fields are good example cases where reservoir oil with a total resin/asphaltene content of less than 10% is susceptible to acidity under high reservoir temperatures. Sediment deposition occurs with HCl concentrations as low as 37.9%. In fact, the temperature does not directly affect the “stability” of the system but rather accelerates resin/asphaltene destabilization. Thus, acidizing operations performed without consideration of the oil chemical background may trigger secondary channel colmatation in the form of asphalt/resin/paraffin deposition 2623
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Figure 3. Variation of asphaltene texture and character with different destabilization methods and/or conditions (a, pentane induced; b, CO2 induced, Pres and Tres; and c, pressure induced, Psat and Tres).
Figure 4. Asphaltenes.
Figure 5. Sludge (asphaltene) deposition upon the reaction of mud acid (12% HCl/3% HF solution) with the Lower Hittite oil (Nh-1) from the Vankor oil field.
(ARPD). Acidizing under these conditions is especially dangerous at high temperatures that boost the destabilizing effect of acid on the reservoir oil. These considerations make sludging/crystal deposition tests necessary prior to acidizing. Acid agents should be able to prevent and counteract these processes. Acid/reservoir-fluid compatibility tests help minimize the risks associated with sludging and emulsification, which impair reservoir characteristics by reducing permeability. Compatibility tests were carried out with some commercially available acid solutions as well as some HCl solutions modified by the authors. Overall, more than 20 acid solutions were tested. Oil samples selected for the tests had been collected from various
Figure 6. Emergence of acidoil emulsions: (a) emulsification with different acid/oil ratios (from left to right) 1:3, 1:1, and 3:1 (the initial fluid levels are marked by notches) and (b) acidoil emulsion on a 100mesh sieve.
Rosneft carbonate reservoirs, with reservoir temperatures ranging from 20 to 146 °C; the samples had diverse chemical and physical properties, with viscosities that ranged from 2 to 186 cP in reservoir conditions and densities that ranged from 0.760 to 0.937 g/cm3 in surface conditions. The results of these compatibility tests showed that almost all of the acid solutions produced stable acidoil emulsions (Figure 6). In carbonate reservoirs, the acid bypasses colmatated (clogged) zones caused by emulsification. The latter is seen as a positive factor because of the blocking effect of the emulsion that causes carbonate matrix dissolution and, hence, acid diversion; however, the generation of a stable emulsion may lead to problems during oil treatment. Therefore, this phenomenon is not critical for carbonate reservoirs, provided that the initial volume of the reaction products and oil extracted after the treatment operations during the course of production is used separately from the process oil and products to avoid contaminaion. The majority of the tested oil samples gave viscous sludge or solid-particle sediments when mixed with nonmodified inhibited hydrochloric acid (12 and 24%). Most of these samples were highly viscous; i.e., they had larger resin/asphaltene contents. Sludge or solid-particle sediments are unacceptable because they could clog and irrecoverably damage the matrix pore structure. Reservoir oil is especially susceptible to sludging at high reservoir temperatures when even low acid concentrations cause the precipitation of crystalline sediment. The best results in the acid/oil compatibility tests were achieved with acid solutions containing anti-sludging modifiers 2624
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Figure 7. Sediment dropout affected by the resin/asphaltene (R/A) mass ratio (mresins/masphaltenes).
and with a solution containing a complex modifier: a multicomponent mixture of anion and cation surfactants with different chemical compositions. The complex modifier not only inhibits emulsions and sediments during its interaction with reservoir fluids but also reduces the interfacial tension on the acid/oil boundary. The compatibility of oil with acid solutions is considerably affected by the resin/asphaltene mass ratio (R/A). Figure 7 shows the dependence of the occurrence of asphaltene associate dropout upon the R/A (mresins/masphaltenes) ratio. The “compatible/incompatible” transition interval lies in the range of 3.54.5; the probabilities of asphaltene association and no asphaltene association are equal within this interval. Asphaltene stability in oil is not affected by the R/A mass ratio but rather by the R/A molar ratio. Because different oils have various asphaltene and resin structures, it is apparent that their molecular weights, i.e., the mass ratio of resins to asphaltenes, can be different with equal molar ratios. To prevent sludging/sediment deposition upon contact of the acid agent with the high-viscosity reservoir oils (particularly those with high asphaltene content), the use of a preliminary “buffer” solvent slug prior to acidizing is recommended. Asphaltenes are nearly insoluble in paraffinic hydrocarbons, acetone, and alcohol. Hydrocarbon solvents should be aromatic or terpenic, such as Nefras A150/330 petroleum aromatic solvent. The use of such a solvent will also reduce the oil viscosity and the interfacial tension on the acid/oil phase boundary. As previously mentioned, even very low fluid acidities may produce asphaltene deposition in anomalously high-temperature reservoirs. In these cases, apart from using an aromatic solvent preliminary slug,27,28 it is highly advisible to use anti-sludging modifiers as well as alternative carbonate-dissolving agents instead of conventional acids, such as organic acids (acetic acid, formic acid, and higher fatty acids). Acid-generating agents (organic acid esters and aluminum chlorides, which slowly produce acid in water) or complex agents are also good alternatives. A wide range of acid solutions (inorganic and organic) or acidgenerating agents as well as various additives, viz. inhibitors, diverters, demulsifiers, stabilizers, and modifiers (that modify reservoir rock wettability), are currently used for optimal well
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stimulation. The use of these substances helps prevent or offset the risks of secondary matrix colmatation following acidizing operations. However, some modifiers whose function it is to boost the positive effect of acidizing may “backfire” and produce incompatibility. The reservoir temperature also plays an important part in the process. Therefore, acid solutions should be tested under real field conditions (according to where they will be applied). As the properties of oils (i.e., their composition) change, their compatibility with acid solutions will also change, which underscores the necessity of carrying out compatibility tests under field conditions prior to acidizing. Estimation of the Kinetic Parameters Describing the Reaction Rate of Acid Solutions with Oil- and Water-Saturated Rock Samples. The two important indicators of acidizing efficiency are improved treatment selectivity and deeper agent invasion into the rock. The former can be achieved by modifying the oil/acid boundary interfacial tension and the wettability of the porous rock medium, whereas the latter can be achieved by decelerating the activity of the agent with the rock matter. Acid activity can be decelerated by slowing acid diffusion toward the rock surface, reducing the concentration of hydrogen ions (H+) in the solution and forming a protective sorption layer on the rock surface. The chief factors that determine and affect these processes are the nature of the acid, its concentration and injected volume, physical and chemical properties, reservoir temperature, operation pressure, rock composition, reservoir structure, acid injection rate, and the presence of additives. One of the most available and efficient methods of decelerating the acid reaction is the use of specific additives in the solution or the replacement of HCl with an organic acid (acetic, formic, etc.). Alternatively, high reservoir temperatures can be used for chelated complexes. The choice of the specific acid agent should be based on preliminary tests on real rock samples. In this study, tests were also performed to select an optimal acid solution that would exhibit a slower reaction with water-saturated rock than with oil-saturated rock and would provide for maximum fluid percolation. Various methods exist for investigating rock dissolution kinetics. The most widely used are the rotating disk method29 and the measurement of acid activity with carbonates by the rate of carbon dioxide evolution using a pressure-gauge system.30 In our tests, the latter method was employed. This method features excess acid reacting with the disintegrated rock matter saturated with either oil or water. This test provides better insight into the mechanics of the two wettability effects on the pore surface: hydrophobization and hydrophilization. Moreover, the use of specific oil and core samples taken from the target field improves the accuracy of physical and chemical simulation of the in-well processes. In this method, the quantity of carbon dioxide (CO2) evolving during the acidizing of a core sample within a given period is measured. The “raw” test results were interpreted with the assumption that the HCl/carbonate reaction kinetics should be subject to the basic rules governing topochemical processes31 in non-uniform media. The HCl/carbonate reaction kinetics can be described by the modified AvramiYerofeev equation: νt ¼ νo ð1 expðKt n ÞÞ
ð2Þ
where νt is the quantity of CO2 evolved (mM) during the period 2625
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Table 1. Kinetic Parameters of Acid Solution Reactions with Water-Saturated Core Samples from Praskoveyskoye Well 65 ν0 acid composition
Table 2. Kinetic Parameters of Acid Solution Reactions with Oil-Saturated Core Samples from Praskoveyskoye Well 65 ν0,
Vmax
(mmol) k (cn)
n
tmax (c) (mmol/s) facida
acid composition
Vmax
mmol k (cn)
n
tmax (c) (mmol/s) 0.044 0.027
facida
12% inhibited HCl KSPEO-2
1.255 1.100
0.016 0.153
1.448 0.530
7.03 9.38
0.047 0.030
1.000 1.564
12% inhibited HCl KSPEO-2
1.180 0.957
0.003 0.017
1.883 1.288
14.06 7.03
1.069 1.742
10% EDTA
1.312
0.066
0.839
9.38
0.038
1.254
10% EDTA
1.306
0.055
0.626
14.06
0.017
2.834
10% OEDP
0.908
0.023
1.343
0.02
0.040
1.165
10% OEDP
0.727
0.112
0.564
0.06
0.029
1.596
KS-1
1.091
0.102
0.732
11.72
0.030
1.580
KS-1
1.133
0.075
0.611
11.72
0.020
2.416
KS-2
0.967
0.012
1.332
9.38
0.023
2.054
KS-2
0.772
0.098
0.491
14.06
0.012
4.321
KS-3
1.128
0.085
0.624
9.38
0.025
1.905
KS-3
0.878
0.035
0.833
9.37
0.016
3.026
KS-4
1.507
0.048
0.720
11.72
0.024
1.981
KS-4
0.984
0.073
0.625
10.55
0.018
2.598
a
facid was estimated at Vmax for 12% HCl with a water-saturated medium using eq 2.
facid was estimated at Vmax for 12% HCl with a water-saturated medium using eq 2.
of time t (s), ν0 is the maximum quantity of CO2 evolved (mM), and K is a reaction constant (sn). The exponent n can serve as a measure of the anisotropy of the medium. For 0 < n < 1, no induction period is observed on the reaction kinetics curve; for n > 1, the initial reaction rate is less than the maximum rate, which is shown by a weakly sloping start of the curve. Most induction periods in an oil-saturated porous medium are affected by relatively slow acid diffusion through the oil film and exhibit values of n > 1. The degree to which all of the components in the acid solution influence the reaction rate was estimated using an acid factor that combined all of the effects produced by the modifying additives (modified diffusion and surface tension). This factor is given by the ratio of the maximum reaction rate of the standard (non-modified) acid solution with a water-saturated carbonate medium to that of the modified acid solution being tested.31,32
To illustrate these considerations, some results of kinetics tests for the carbonate-type Praskoveyskoye field (Tres = 126146 °C) are given below. The tests involved solutions in which HCl was replaced with carbonate-active complexing agents: nitrilotrimethylenephosphonic acid (NTP), oxiethyldendiphosphonic acid (OEDP), and ethylenediaminetetraacetic acid (EDTA). These agents produce water-soluble ferrocomplexes that generate no sludge when mixed with reservoir oil. NTP and OEDP sequester calcium ions from the solution and are remarkably calcium-active at high temperatures. A number of solutions with reduced acid activity were also tested (see KC-1, ..., KC-4 in Table 1). These agents (KC-1, ..., KC-4) are based on either an acidified NTP solution (KC-1) or an active aluminum chloride solution with different concentrations of monosulfate alkaline additives (KC-2, ..., KC-4). The use of acid solutions with monosulfate alkaline additives (composed chiefly of hemicelluloses and lignosulfonates) has been described by Fredd and Fogler.16 The tested solutions were compared to 12% inhibited HCl and the KSPEO-2 agent manufactured by PolyEx, which contains wettability-modifying surfactants and was used for acidizing at Praskoveyskoye. The tests used core samples taken from Well 65 from the Maastricht stratum of Praskoveyskoye at a temperature of 90 °C. Although the reservoir pressure was significantly higher, the tests allowed for comparison of the agents. The results of the gas-evolution kinetics tests allowed for the conclusion that even weak agents, such as OEDP or EDTA, that manifest virtually no activity with carbonates at low temperatures become markedly carbonate-active at high temperatures (see Tables 1 and 2). As shown in Table 1 and Figure 8, several agents (especially KC-2) have relatively high acid factor (facid) values. The presence of modifying surfactants in KSPEO-2 makes it comparable with 12% HCl with regards to its activity with oil-saturated rock and accounts for its influence on surface phenomena. As previously mentioned, the value of facid should be high in high-temperature/ low-viscosity conditions. An agent with a high acid factor is more likely to percolate deeper into the matrix, to reduce contamination of the wellbore area, and to connect new, untapped permeability channels (macro- and microfractures). Otherwise, the agent would only reside in the wellbore area without counteracting contamination.
facid
dVCO2 dt max, non-modified ¼ dVCO2 dt max, modified
ð3Þ
For values of facid < 1, the dissolution rate of the standard (non-modified) acid solution is greater than that of the analyzed modified solution (in this case, 12% HCl) and vice versa. All of the test curves were well-described by eq 2 with n > 1. Therefore, all of the tested core samples can be considered anisotropic, with most of the reactions being diffusive-kinetic. Because the acid dissolution of carbonate matter is limited not by surface reactions but rather by diffusive processes, especially at high reservoir and rock temperatures in the case of limestone, it becomes increasingly difficult to control the intensity of the process at high temperatures. Therefore, a low efficiency of HCl acidizing in high-temperature carbonate reservoirs is observed because it becomes impossible to drive the agent into remote zones of the reservoir. Such an acidizing operation could result in intensive dissolution of the rock matter in the near-wellbore area with the development of vuggy zones and adverse consequences. In the worst case, this could lead to the dissolution of the casing and increased risks of water and gas breakthrough.
a
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Figure 8. Comparison of acid factors facid of the investigated agents for oil-saturated rock with the corresponding invasion depths, where L and L0 are the invasion depths of the investigated agents and the 12% HCl solution, respectively: (A) 12% inhibited HCl, (B) 10% EDTA, (C) acid composition “KSPEO-2”, (D) acid composition “KS-1”, (E) acid composition “KS-4”, (F) 10% OEDP, (G) acid composition “KS-3”, and (H) acid composition “KS-2”.
Table 3. Pumping Schedule for the Field Case stage
fluid
1
WG-40DS linear
2
water
3
12% KSPEO-2
4
WG-40DS-1,8
stage volume
average pump rate
pump time
(m3)
(m3/min)
(min)
5
0.7
7.1
5
0.7
7.1
10
1.3
7.7
10
1.3
7.7
cross-linked 5
12% KSPEO-2
15
1.3
11.5
6
WG-40DS-1,8
20
1.3
15.4
7
cross-linked 12% KSPEO-2
25
1.3
19.2
8
flush
5
0.5
6
’ FLUID PLACEMENT AND DIVERSION: OPTIMIZING THE DESIGN OF MATRIX TREATMENTS The greatest challenges in matrix treatments are often fluid placement and diversion. Matrix acidizing is usually most beneficial when applied across a large productive interval with appreciable flow capacity. However, in such cases, it is highly probable that multiple intervals are present, each with a different injectivity. Because treatment fluids will flow along the path of least resistance, the higher permeability intervals will most easily accept the acid and the remaining zones will disproportionately receive smaller amounts. Current requirements suggest that the design of a carbonate rock matrix treatment should be calculated on the basis of models of key physical and chemical processes by specialized software. In wells with a heterogeneous vertical permeability, the problem of acid distribution across the reservoir zone cannot be addressed correctly without using a numerical simulation. Moreover, numerical simulators help find solutions for the feasibility assessment of acidizing operations by simulating scenarios with different injection volumes and rates, agent stagings, and initial economic conditions. The design optimization problem in carbonate reservoir acidizing using viscous diverter fluids was described in a previous work.33 The mathematical model of the acidizing process was created on the well scale. This model accounts for the flow of insoluble clay and silica particles in a porous medium and their deposition at the pore throats. Core laboratory tests showed that
the treatment pressure is affected by a suffosion process. Numerical simulation allowed for the calculation of the acid concentration and pressure in the reservoir at different injection stages, porosity and permeability dynamics, the treating agent distribution and flow in the layered heterogeneous reservoir, the skin factors in target zones, and the effect of the diverter fluids. These calculations help to determine the optimal parameters that drive the acidizing efficiency. The incremental oil production rate and variance of post-treatment productivity for the heterogeneous reservoir are used as the target parameters for treatment optimization. The developed simulator of the heterogeneous laminated reservoir acidizing was applied to evaluate the real field operations, and the results were consistent with actual historical data. One way to validate simulated data is to compare them to actual field measurements. The simulator capability was validated against the acidizing data for selected wells run by the Rosneft Oil Company in 20092010. The model was adjusted against the actual bottomhole and wellhead pressure dynamics (pwb and pwh, respectively) by minimizing the corresponding functions. I1 ¼
simulated 2 Þ f min ∑i ðpactual wb½i pwb½i
I1 ¼
simulated 2 Þ f min ∑i ðpactual wh½i pwh½i
Acidizing was performed in a multilayer carbonate reservoir with chemical deflection using INER cross-linked gel for one field example. Table 3 presents the entire operation workflow. The results of the comparison between the simulated and measured bottomhole pressures are shown in Figure 9. Curves 1, 2, 3, and 4 represent the simulated bottomhole pressures, the measured bottomhole pressures, the wellhead pressure, and the treatment rates, respectively. The simulated pressure responses compare well to the measured pressure responses. The adjusted model was later used as a basis for predicting the liquid rates and incremental oil rates of the analyzed wells. The simulated and actual (observed) liquid rates and incremental production rates from acidizing are shown in Figure 10. A correlation analysis was performed for treated wells. The described examples prove that the developed simulator of carbonate rock acidizing is sufficiently robust in predictions, and it can be used for acid treatment design, given moderate uncertainties in the input reservoir parameters. 2627
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Figure 9. Comparison of predicted and bottomhole pressures for the field case.
Figure 10. Cross-plots of actual versus simulated data: (a) liquid rate and (b) incremental oil rate.
The numerical simulator developed by the authors can calculate an optimal injection rate and agent slug volume for each treatment stage and an optimal deflecting agent/acid agent ratio. The simulator also calculates the number of required deflecting stages and the distribution of the acidizing stages for the total acid solution volume to be injected.33 Using such a simulator during acidizing design for non-uniform carbonate reservoirs ensures maximum treatment efficiency. Figure 11 shows that a significant stimulation effect took place and that the stimulation effect predicted by the simulator is in good agreement with the measured data.
’ SUMMARY The proposed integrated approach to acidizing operations in carbonate reservoirs includes analysis of geological and physical data, selecting candidate wells for acidizing, determining the causes of reduced flow characteristics in the wellbore
area, and designing and implementing the acid treatment operation. Acid compositions should be selected on the basis of chemical analysis and should be tested in field conditions (according to where and how they will be applied). Both the nature of the solution and any modifying additives present in it significantly affect the speed of carbonate dissolution by the acid solution. Careful consideration of acid solution properties for a given geological/geophysical environment boosts the overall efficiency of acidizing by increasing the sweep radius and preventing insoluble compositions that would otherwise clog the near-wellbore pore space. The final stage of acidizing includes collecting, analyzing, and interpreting the results of the operation. Such analysis allows the factors affecting the efficiency of the acid treatments to be pinpointed. The use of a numerical acidizing simulator for the optimization of the acidizing design for a given well is important. 2628
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Figure 11. Pre-acidizing and post-acidizing fluid rate dynamics in a well.
’ AUTHOR INFORMATION Corresponding Author
*E-mail:
[email protected].
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