Corrosion and scaling represent a challenge to equipment manufacturers and operators the world over.
The case is even more severe for the petroleum industry as serious corrosion and scaling mean safety
and environmental issues, well production decline and/or temporary suspension of production, which can impact energy supply. Accordingly, it is essential for petroleum operating companies to invest in corrosion and scaling control.
Multistage acid fracturing technology has been credited with unlocking oil and gas reserves around the world that were previously dismissed as unrecoverable or uneconomic, enabling operating companies to sustainably produce from tight hydrocarbon-bearing reservoirs.
Corrosion inhibition is especially challenging for multistage acid fracturing wells because many of these wells are drilled in high temperature gas formations and so produce some quantity of water with hydrogen sulfide (H₂S) and carbon dioxide (CO₂), which contribute to corrosion and scale. Furthermore, multistage acid fracturing wells are often stimulated with large volumes of highly concentrated hydrochloric (HCl) acid — 26% to 28% — in each stage, which makes the wells vulnerable to severe corrosion if they are not protected appropriately.
Simply put, corrosion is the loss of electrons, causing the metal to go into solution in ionic form (as ores); if you can prevent this loss of electrons, then you have successfully inhibited the corrosion. This report discusses the protective measures used to manage corrosion for multistage acid fracturing wells drilled in the high temperature, sour gas-bearing Carbonate-K reservoir in Saudi Arabia. The measures include material selection, acidizing corrosion inhibition package design and selection criteria, and base water quality control.
Moreover, since corrosion and scale go hand-in-hand — because corrosion develops underneath scale deposits, then starts digging into the metal — this article presents a step-by-step method to predict the scaling tendency of a well based on the geochemical analysis of a water sample, enabling proactive containment.
Additionally, the report presents a pioneering recommendation for managing corrosion during acid fracturing that involves applying electro-kinetics technology. This article explores other initiatives as well — both operational and laboratory — where innovation can further reduce corrosion rates.
A major gas producing reservoir in the Arabian Peninsula is the Carbonate-K. The Carbonate-K reservoir is classified as a heterogeneous reservoir that consists of dolomite and limestone with moderate to low permeability and high formation bottom-hole temperature (BHT), Fig. 1. With temperatures ranging between 260 °F and 320 °F, the Carbonate-K reservoir contains close to 10% mole hydrogen sulfide (H₂S) and over 3% mole carbon dioxide (CO₂), Table 1. The ratio of produced water to gas is between 1.5 bbl/million standard cubic ft (MMscf) and 2 bbl/MMscf, while the ratio of condensate to gas is between 30 bbl/MMscf and 50 bbl/MMscf¹.
During the early days of the Carbonate-K reservoir development, the more prolific layers were targeted with vertical stimulated wells that could deliver commercial gas production rates. Today, the focus having shifted toward the less prolific tight layers, horizontal and multilateral drilling using the latest geosteering technology is being used. Depending on the reservoir development and after processing the open hole logs, some of the Carbonate-K wells were completed using multistage acid fracturing technologies. Economic and sensitivity analyses of multistage acid fracturing wells using a semi-analytical, multiple fracture production simulator have indicated that the optimum number of stages in Saudi Arabian wells, depending on lateral length — reservoir contact — and permeability, is in excess of five acid fracture stages, Figs. 2 and 3.
The greater number of fracture stages for multistage acid fracturing wells calls for large pad volumes and acid sequences. Initially, large treatment volumes, approximately 1,800 gal/ft of net interval to be stimulated, of 28% gelled hydrochloric (HCl) acid were used for most acid fracturing treatments in these sour wells. To achieve increased fracture half-lengths, emulsified acid was substituted for a portion of the 28% (or 26%) gelled acid; emulsified acid has proven to be an acid system with more retarded action, and so spends more gradually than straight gelled acid, thereby increasing etched fracture length. Recently, stimulation strategies have evolved to apply smaller volumes — 1,000 gal/ft to 1,200 gal/ft — and more efficient designs using multistage acid fracturing hardware (completion).
Table 2 shows the pumping sequence and fluid volumes for the first stage of a five-stage acid fracturing well producing sour gas in the Carbonate-K reservoir. The initial pad fluid volume is used to initiate and propagate a fracture that is wide and long enough to transport acid into the formation easily and quickly. The pad volume must be large enough to yield a fracture length adequate for a particular formation as well as give the vertical coverage for all pay zones of interest. Too little pad volume may not create a fracture long and wide enough for optimal production. On the other hand, excessive pad volume, rather than increase the etched fracture area — the acid may already have been spent before it reaches all of the fracture that was created — will more likely damage the formation. In fact, wells exhibiting moderate to good reservoir quality, where the objective is creating highly conductive fractures, specifically require low pad volumes².
The large, highly concentrated acid volumes pumped in each stage of the treatment — along with the high temperature in a sour formation environment — make these wells susceptible to corrosion. Therefore, it is essential to have a proactive corrosion management program in place.
The corrosion phenomenon occurs because metals tend to revert back to their initial stable forms in nature, i.e., metallic ores. Corrosion involves both oxidation and reduction reactions. Oxidation is any reaction in which a given substance loses electrons, whereas reduction is any reaction in which a given substance gains electrons. Accordingly, when a substance yields electrons, it is called a reducing agent, whereas when a substance gains electrons, it is called an oxidizing agent. While oxidation takes place at the anode, reduction takes place at the cathode³.
The tendency of a metal to donate electrons depends on its location in the electromotive force series. Generally, any given ion is a better oxidizing agent, or oxidant, than the ions above it on the electromotive force series table³.
When corrosion takes place, it attacks metals in producing systems and facilities, resulting in extreme damage. The corrosion byproducts can be ions in solution, salts on metal and hydrogen gas. Water provides the medium for both corrodents and corrosion byproducts. The components in a fluid that promote the corrosion of steel in producing operations are oxygen, CO₂, H₂S, salts and organic acids.
Sour corrosion takes place when metal contacts H₂S and moisture. The presence of water in such an environment results in severe corrosion; H₂S causes sulfide cracking and embrittlement in production tubing, after which deposits, such as iron sulfide, develop on the surface of the steel⁴.
This article discusses the material selection, acidizing corrosion inhibition package design and selection criteria, and base water quality control needed to prevent corrosion and scaling in multistage acid fracturing wells in the sour corrosive environment of the Carbonate-K reservoir.
Moreover, since corrosion and scale go hand-in-hand — because corrosion develops underneath scale deposits, then starts digging into the metal — this article presents a step-by-step method to predict the scaling tendency of a well based on the geochemical analysis of a water sample.
Additionally, this article presents a pioneering recommendation for managing corrosion during acid fracturing that involves applying electro-kinetics technology.
Material Selection For The Multistage Acid Fracturing System
The multistage acid fracturing system hardware is made of standard, P-110 grade, mild steel material in the majority of the multistage fracturing jobs around the world, including in Saudi Arabia. Table 3 presents the elemental composition of the P-110 grade steel used in most multistage acid fracturing wells in Saudi Arabia. This material complies with the National Association of Corrosion Engineers (NACE) standards for material selection in terms of both temperature and partial pressure tolerance. Laboratory experiments have been carried out to confirm that acid contact during the fracturing operation will not cause any corrosion or pitting in excess of the acceptable corrosion rate of 0.05 Ib/ft², which correlates to an acceptable pitting index of 0. Table 4 shows the results of three laboratory experiments that preceded the acid fracturing operation of a multistage acid fracturing well used in a study. The experiments were carried out at a temperature of 275 °F for 4 hours, and the observed corrosion rate and pitting were within the acceptable limits.
Also, the standard rule is that the multistage fracturing equipment must have a yield strength that is rated equal to or greater than the production tubing itself; therefore, the rating and material of acidizing hardware and well tubulars at a minimum need to match. In the Carbonate-K reservoir, C-95 is the typical tubing grade for the sour gas producers, so P-110 is obviously a higher grade — ranging between 110,000 psi and 140,000 psi of yield strength. In compliance with the NACE metallurgy guidelines for H₂S and for well environments of greater than 175 °F, the H₂S reaction is fairly well suppressed; therefore, the P-110 grade material is the cost-effective option for the specific case of these multistage acid fracturing wells for sour gas.
Acidizing Corrosion Inhibition
An acidizing corrosion inhibitor is a chemical formulation that decelerates the rate of corrosion during well acidizing; it is designed to protect the well tubulars. The type of inhibitor used for acidizing operations is an adsorptive inhibitor. Adsorptive inhibitors provide protection by forming a thin film on the surface of the metal, changing the electrochemical potential of the metal³.
The acidizing corrosion inhibition package includes a corrosion inhibitor, inhibitor intensifier and dispersion/solubility agent. Inhibitors can be classified as organic or inorganic. Organic inhibitors are those that contain complex carbon-to-carbon compounds, whereas inorganic inhibitors contain crystalline salts, such as sodium phosphate³. The inhibitor intensifier is used to enhance the performance of corrosion inhibitors in certain scenarios. For instance, they are added to enable effective inhibition at higher BHTs, e.g., 350 °F⁵⁻⁷. The dispersion/solubility agent functions to make the inhibition components more dispersible/soluble in acid and base water.
The mechanism of acidizing corrosion inhibition encompasses four main processes, Fig. 4: (1) The chemsorption process, in which the molecules of the inhibitor chemically tie to the surface of the metal; (2) The polymerization process, during which a protective film is developed to isolate the metal from the acid; (3) The discharge process, where the resistance to current flow is increased as ions are excluded; and (4) The polarization process, during which the potential difference between the anodic and cathodic reactions is reduced³.
The recipe of the acidizing corrosion inhibition package is case specific. The criteria for selecting the inhibition system are functions of the well tubulars’ composition, the acid system used for fracturing, BHT, protection time and the formation environment.
In the case of the multistage acid fracturing wells in Saudi Arabia, the high temperature of the Carbonate-K reservoir dictates the incorporation of special inhibitors for high temperatures, along with some modification in the acid system for certain wells⁸. In spite of the extra expense associated with these special inhibitors, laboratory tests have confirmed their effectiveness in inhibiting acidizing corrosion at elevated temperatures.
The presence of high H₂S content in the Carbonate-K reservoir poses a serious corrosion and scaling challenge. In the presence of water, H₂S is very corrosive to metal. The following common equation expresses the H₂S reaction with metal:
H₂S + Fe + H₂O → FeSx + 2H + H₂O (1)
To abate the aggravating effect of H₂S on tubulars already subject to HCl acid, H₂S scavengers are added to the treatment recipe. These scavengers remove H₂S from the acidizing fluids by reacting with it to form more stable compounds.
Figure 5 shows the recommended procedure for selecting and designing the acidizing corrosion inhibition package. The first step is to review well data and determine the presence of acid gases and their content, the composition of tubulars, reservoir temperature, formation composition, and protection time. Second, select the acid type that will achieve the most etching without causing any undue damage to the well and formation. Third, select the inhibitor that will provide effective protection and also suits the selected acid type and formation conditions. Fourth, conduct laboratory experiments at reservoir conditions using loading tables/plots. Finally, evaluate the outcomes of the laboratory tests, post-job results and lessons learned.
When an analysis of post-acidizing flow back samples for some wells in the Carbonate-K reservoir that underwent acid fracturing operations indicated that the samples contained live acid, it was decided to increase the soaking time to 3 hours and increase the volume of the overflush stage⁹. For multistage acid fracturing wells, it is recommended to set the soaking time in the range of 4 to 6 hours to allow sufficient time for the diversion chemicals — or fiber — to degrade completely. At the same time, it is necessary to flow back the well before the corrosion inhibitor loses its effectiveness.
Moreover, if the inhibition package is to be effective, it is important that the components are mixed properly on the job site. Furthermore, they should be mixed right before pumping the treatment as any significant delays will drastically reduce their inhibition effectiveness.
On a special note, as most of the multistage acid fracturing wells are horizontal wells, attention should be paid to prevent any concentrated corrosion in the deviated parts of the tubular due to acid entrapment.
One of the biggest challenges of hydraulic fracturing is water availability and quality. The base fluid for the acid fracturing treatments in the multistage acid fracturing wells in the Carbonate-K reservoir is water. Water is preferable to oil, mainly because it is more cost-effective, environmentally friendly, readily available and convenient to handle and dispose of¹⁰.
The goal of water quality control during acid fracturing is to achieve the objective of the pumping operation while controlling any potential corrosion that may be induced by the injected water in a manner that enables cost containment.
To achieve that goal, the water used should meet the following recommended guidelines:
Free of suspended materials to prevent plugging up porous spaces.
Maximum iron content of 125 ppm.
Maximum bicarbonate content of 600 ppm.
Maximum chloride content of 3,000 ppm.
Does not contain carbonate.
Compatible with the formation fluids.
Also, it is noteworthy to mention that the sodium to calcium ratio (Na/Ca) of the injected water should be lower than that of the formation water because Na-based clays swell more than Ca-based clays³.
Scaling Diagnosis and Prediction
Corrosion and scale go hand-in-hand because corrosion develops underneath scale deposits, then starts digging into the metal. In managing scale, it is important to identify the type of scale that is forming in a given well, determine its solubility and devise a strategy to prevent it. Both X-ray diffraction and X-ray fluorescence (XRD/XRF) compositional analyses run on several scale samples from wells in the Carbonate-K reservoir have shown hard inorganic scale types, mainly iron compounds — iron oxides/hydroxides and iron sulfides — and calcium carbonate (CaCO₃)¹¹.
Deposited from aqueous solutions, scale can restrict fluid flow. Because scale is formed from aqueous solutions, prediction of its occurrence is made possible by geochemical analysis of a well’s produced water. Table 5 shows results of the water analysis conducted for a multistage acid fracturing well in the Carbonate-K reservoir. The pH of the water sample is 7.7.
Hard water, containing high quantities of metal ions, such as iron, calcium and magnesium, has often been associated with scale formation and deposition. The hardness of a water sample can be expressed in terms of overall CaCO₃. This is achieved by converting the concentration of metal ions in the water to a CaCO₃ equivalent using the equivalent weight of CaCO₃³. The following example shows how the hardness of a water sample is determined — calculations are made for the water composition shown in Table 5.
The hardness of the water expressed as CaCO₃:
Intensive chemical analysis of several water samples from the Carbonate-K reservoir has indicated that the produced water is hard with a high mineral content. When the solution becomes oversaturated, minerals will precipitate, initially as a fluffy scale, and then hard scale will form¹².
Professor Chilingar of the University of Southern California has developed a simple, yet powerful step-by-step technique to predict the tendency for scale formation. His work is an extension of previous work completed¹³⁻¹⁵. The main steps are shown here:
For CaCO₃ Scale
The ionic strength for each ion should be calculated using the conversion factors in Table 6.
The value of constant K is determined using the plot in Stiff and Davis (1952)¹⁴. Next, pCa and pAlk is determined using the plot in Langelier (1936)¹³.
The pH at saturation (pHₛ) is calculated as follows: pHₛ = K + pCa + pAlk.
From the plot in Jones (1988)¹⁵, the solubility factor, Sf, is determined. Consequently, the R’ ratio is calculated as follows:
From the plot in Jones (1988)¹⁵, the pH is determined.
The stability index (SI) is calculated as follows:
A positive value of SI implies that the water is oversaturated with CaCO₃ and CaCO₃ scale is likely to form, whereas a negative value of SI implies that CaCO₃ scale is unlikely.
If scaling is likely to occur, it is recommended that scaling inhibitors be used. Most scaling inhibitors work by plating the tiny crystals of scale and preventing them from growing bigger to form hard scale.
Application Of Electro-Kinetics Technology
The concept of applying direct current electrical technology for improved well performance originated back in the 1960s when Professor Chilingar and his students at the University of Southern California undertook extensive laboratory testing of the idea. Today, electro-enhanced oil recovery is yielding successful results in California and at the Alberta heavy oil fields¹⁶.
It has also been found that electro-kinetics technology can address the challenge of limited depth of radial penetration for acidizing pumping operations in tight heterogeneous carbonate reservoirs. Increasing the volumetric rate of acid flow using two electrodes — anode and cathode — results in a deeper depth of radial penetration, unlocking the full potential of target zones¹⁷. Another advantage that is gained by the use of the anode electrode is corrosion reduction in the well tubulars; the anode (as sacrificial hardware) corrodes and sends electrons to the well tubulars to protect them, Fig. 6.
For this reason, it is recommended that electro-kinetics technology be applied in conjunction with multistage acid fracturing operations in multistage acid fracturing well candidates in the Carbonate-K reservoir, especially where prolonged exposure to high concentration acid is expected.
Conclusions and Recommendations
The material used for multistage acid fracturing systems in Saudi Arabia is standard, P-110 grade mild steel. This material is in compliance with the NACE standards for temperatures above 175 °F. Since all multistage acid fracturing wells in the Carbonate-K reservoir are above this temperature, the P-110 material grade is handy in terms of cost and availability.
As most of the multistage acid fracturing wells are horizontal wells, attention should be paid to prevent any concentrated corrosion in the deviated parts of the tubular due to acid entrapment.
If the inhibition package is to be effective, it is important that its components are mixed properly on the job site. Also, they should be mixed right before pumping the treatment as any significant delays will drastically reduce their inhibition effectiveness.
The pHs, used to predict scale, is an empirical value that involves extensive experimental work.
Intensive chemical analysis of several water samples from the Carbonate-K reservoir has indicated that the produced water is hard with a high mineral content. When the solution becomes oversaturated, minerals will precipitate, initially as a fluffy scale, and then hard scale will form.
When electro-kinetics technology is applied in multistage acid fracturing wells during acidizing operations, corrosion will work on the sacrificial anode rather than on the production tubulars. After acidizing, the anode will look like an eaten up sponge — full of holes — as a result of corrosion.
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Technical Paper authored by: Mohammed A. Al-Ghazal and Saad M. Al-Driweesh