Acid fracturing treatments are used to enhance gas production from tight, deep carbonate reservoirs in Saudi Arabia.The produced gas has a regional variation between 0 and 10 mol% H[2]S. This variation in H[2]S content has impacted the metallurgy of well tubulars used in these areas.Gas wells in the high H[2]S area are completed with low-carbon steel (L-80 and C-95); those in the low H[2]S area are completed with super Cr-13 tubulars. Acid systems used to fracture these wells included: regular, emulsified, and in-situ gelled acids, all based on 28 wt% HCl.However, 15 wt% HCl - 9 wt% formic acid was used to stimulate wells completed with super Cr-13 tubing. High temperatures (275ºF) encountered in deep wells, the presence of high H[2]S content and the use of large volumes of concentrated acids render corrosion control of tubulars a very difficult task. Experiments were performed to develop a cost-effective acid system to enhance the productivity of deep gas wells, while maintaining the integrity of well tubulars.Acid fracturing treatments were monitored in the field and well flow back samples were collected following these treatments.The concentrations of key ions were measured in these samples including iron and manganese for completions with low-carbon steel tubulars and chrome, molybdenum, and nickel for completions with super Cr-13. Analysis of flow back samples following the initial acid fracturing treatments showed that the return samples contained high concentrations of acid (up to 16 wt% HCl) and total iron (up to 20,000 mg/l). The presence of iron was a major concern during acid fracturing treatments. Modifications of the corrosion inhibitors package, increasing soaking time and over flush volume resulted in better results. Most importantly, the integrity of well tubulars was maintained. This paper discusses lab studies and application of these modifications in the field. Introduction Acid fracturing treatments have been conducted in a deep carbonate gas reservoirs.[1]Various acids are used in these treatments. Almost all of these acids are based on 28 wt% HCl. Corrosion control during these treatment has been a major concern. This is because of the use of concentrated acids, high temperature, and the presence of hydrogen sulfide in some areas in the gas reservoirs. During pumping the acid down the tubing, the acid is continuously depleted from the active ingredients of corrosion inhibitors by the adsorption and/or polymerization on the metal surface. The active ingredients of corrosion inhibitor adsorb to the metal surface and form a thin film that protects the metal leaving the live acid with less inhibition. When the acid reaches the formation its inhibition is further reduced by adsorption on surfaces of rocks.Recovery of the spent acid back through the well tubing may cause corrosion problems if the return fluids contained live acid. This is mainly due to the low levels of corrosion inhibitor in the return fluids. In addition, surfactants, which are used to disperse the inhibitor in the acid, also have very high tendency to adsorb on rock surfaces.[2] This, in turn, leaves the return fluids with minimal dispersivity and poor functionality. In general, cationic or partially cationic corrosion inhibitors adsorb to surface of the rock, especially in the case of sandstone. Nonionic corrosion inhibitors such as acetylenic alcohol show little if any adsorption on rock surfaces. Several authors have addressed the problem of corrosion inhibitor being adsorbed on formation rocks and thereby damaging the formation, altering wettabilty or causing emulsion problems.[3,4] The concern of the presence of live acid in well flow backwas first raised by Huizinga and Like.[3] A similar work was done later by Morgenthaler et al.[4] Their experimental work was done on acidizing of sandstone rocks by HCl/HF acid. Simulated and real spent acids were used to test their effects on low-carbon steel (L-80) and stainless steel (super Cr-13). Both studies agree on that spent acid could be corrosive and may adversely affect the integrity of well tubulars. The extent of the problem can be addressed by a thorough understanding of the composition of the spent acid and its effect on various types of tubing.
Pickle treatments are commonly conducted to remove various contaminants from the wellbore prior to performing chemical treatments in various wells. Introduction of these contaminants into the formation during the treatment can cause loss of well performance, especially in tight formations. These treatments should be designed to remove various contaminants from well tubulars in an efficient and cost effective way. A pickle treatment was designed to clean well tubulars in several wells prior to performing acid fracturing in the carbonate formation. The pickle treatment consisted of several fluids such that each fluid removed one type of contaminants. This paper examines the effects of fluid composition, volume, and placement (bullheading versus coiled tubing) on the efficiency of pickling treatments. More than twenty pickle treatments performed on deep, sour, hot gas wells were examined. To assess pickle treatments in the field, spent acid was analyzed and the concentrations of key ions were measured. Sufficient measurements were made to obtain concentration profiles of chemical species in the spent pickle acid. These profiles were numerically integrated and the data were used to assess the outcome of each pickle treatment. In addition, particulate solids present in the spent acid were separated and analyzed using XRD and XRF techniques. Pickle treatments were conducted on more than twenty gas wells. Some of these wells were perforated, while others were not perforated. Un-perforated wells were pickled using 1.75" high-pressure coiled tubing. On the other hand, perforated wells were pickled using bullheading. The pickle treatments consisted of slugs of surfactants, organic solvents, hydrochloric acid and gelled fluids. Samples of all pumped fluids were collected and analyzed. In addition, well flow back samples were collected every two minutes and were also analyzed to determine their composition. Analysis of spent acids indicated that the major tubular contaminants are mill scale and pipe dope. Spent acid samples collected from deep sour gas wells contained up to nearly 105,500 mg/L of total iron. The efficiency of removing pipe dope was followed by tracing the concentration of zinc, the main acid-soluble constituent in the pipe dope, in the spent acid. The concentrations of acid and iron were used to determine acid reaction with the corrosion products present in the tubing. The concentration of the chloride ions was used to determine the dispersion and mixing behaviour of the acid slug. This paper presents the results obtained from analyzing more than 2000 samples obtained from twenty treatments. The results of this work have been used to enhance the efficiency of the pickle treatments and to significantly reduce the treatment cost. Introduction Formation damage occurs during acidizing or chemical treatments due to the presence of contaminants in the tubing. Several researchers investigated the type and concentration of these contaminants.1–4 The main contaminants present in a typical well tubing are mill scale, iron sulfides, pipe dope, sand, and other fine particles that were picked up during storage and transportation of the tubing string. Oil or condensate may also be present in old producers. One of the contaminants in the wellbore is pipe dope. Pipe dope is used to seal tubing joints, minimize thread erosion and enhance the galling resistance of the threads.5,6 Many authors recommended not to use excessive amounts of pipe dope, which may end in the target zone and cause severe formation damage.1–4
The implementation of extended reach horizontal wells in Saudi Aramco, and in the southern area of Ghawar field in particular, is being increased for production and cost optimization. Logging these wells is a challenge, as production profile of a horizontal section cannot be entirely recorded with conventional coiled tubing (CT). This is mainly because of friction forces between the CT and the wellbore, which cause CT to lock-up significantly shallower than total depth (TD). Although with availability of this limited technique, such as metal to metal friction reducer, still CT reach cannot be maximized effectively. This paper will describe a successful utilization of agitator tool with custom designed e-line bypass that helps CT maximize the coverage of the horizontal section for logging purposes. The agitator tool was incorporated into the Production Logging Tool (PLT) and bottom-hole assembly (BHA). It was activated by pumping to cause the CT string to vibrate, and subsequently reduce the friction contact between the CT and the wellbore to allow CT running beyond the normal lock-up depth. The tool was trial tested in an extended reach horizontal well which has a TD of 12,118 ft. The simulator was showing a predicted lock at 10,400 ft while a dummy run proved a lock-up point occurs at 10,800 ft without activating the agitator. The e-line agitator was activated while the well was flowing at a restricted rate which maximized the reach to the TD and reducing the friction coefficient by around 26%. Different conditions and parameters were conducted in order to understand the best performance of the e-line agitator tool. The implementation of the e-line agitator resulted in extending the reach of CT by an additional 1,300 ft and reaching TD. This additional reach was significant as the last part of horizontal section was contributing water. The production log has been reviewed and showed acceptable measurements. This paper will cover the whole cycle of candidate selection, job design, execution, post job evaluation, lessons learned and conclusion. Introduction Drilling strategy has been shifted from vertical to horizontal at most oil fields in Saudi Arabia due to proven advantages in optimizing production and cost. Even the existing vertical wells, they are being converted to horizontal to prolong their life, improve productivity index and delay water encroachment. Furthermore, the drilling strategy is being developed by drilling more complex wells, such as extended reach horizontal wells, to maximize reservoir contact. This type of well is widely implemented in Saudi Aramco, particularly in the Haradh area, which is located at the southern part of the giant Ghawar field. The extended reach horizontal well can be defined as a well with measured depth (MD) to true vertical depth (TVD) ratio that is equal to or greater than 2 (MD/TVD)1, 2. For this particular field, the horizontal well can be considered as extended reach when its horizontal section is equal to or more than 6,000 ft. These wells act as a challenge for most of the rigless well intervention operations, such as acid treatment and logging, using conventional coiled tubing (CT). The challenge came from CT limitation to cover the entire long horizontal section.
During acid fracturing of carbonate reservoirs, the acid dissolves the rock, creating wormholes which increase fluid loss. Excessive fluid loss lowers the net pressure in the fracture limiting fracture extension, and adversely affects the conductivity of the fracture. To overcome this problem, multiple stages of polymer pads are usually pumped in acid fracturing treatments to reduce leak-off. In addition, synthetic polymers are commonly added to the acid to produce gelled or in-situ gelled acids. The objective of adding these polymers is to reduce leak-off, by increasing the viscosity of the acid. This in turn reduces the rate of mass transfer of the acid to the rock surface. However, several studies have shown that these polymers can cause formation damage. Moreover, the crosslinker can precipitate in the formation causing further damage. Efficient mixing of synthetic polymers in the field is also a concern, especially when the polymers are present in a solid form. To overcome problems associated with polymeric fluids, polymer-free fluids were used for the first time to acid fracture several vertical wells in a deep gas reservoir in Saudi Arabia. The acid fracture treatments consisted of several stages including: viscous pads, emulsified acid, in-situ acid and an inhibited acid. A visco-elastic surfactant system replaced the polymers used in the pad and the leak-off control acid (28 wt% HCl). Calcium chloride produced from acid reactions with the carbonate rock viscosifies the acid in-situ, reducing leak-off volume. Results The pressure response to acid fracture treatments clearly indicates that the surfactant-based system is very effective in controlling acid leak-off during the treatment in wells with a bottom hole temperature of nearly 260°F. Good leak-off control did help in maintaining a constant pumping rate throughout the treatment. Significant increases in both gas production and flowing wellhead pressures were achieved utilizing this new system. In addition, pumping operations were simplified by continuous mixing of the fluids. The nondamaging nature of the system enhanced production rates above expectations. Introduction Saudi Aramco has embarked on an aggressive program to develop its gas fields. The unassociated gas is being produced from two main reservoirs: J (sandstone) and K (carbonate). Hydraulic fracturing is used to enhance gas production from the sandstone reservoir, while acid fracturing is used to increase gas production from the carbonate reservoir.1,2 The present paper will focus on acid fracturing of the carbonate reservoir. The K-formation, which lies between 11,000 and 12,000 ft, is of late Permian age and is divided into four intervals. The two main producing zones are the K-B and K-C, which produce both gas and condensate. These heterogeneous zones are mainly composed of dolomite with streaks of calcite and anhydrite. This type of composition makes them highly soluble carbonates and excellent candidates for acidizing treatments. However, the BHST in this reservoir varies between 250 and 280°F, which presents a challenge in any acid treatment design. High bottom hole temperatures increase the rate of mass transfer of the acid, which causes the acid to spend quickly in the formation. Another problem is the corrosive nature of the acid at higher temperatures, which requires higher inhibitor loadings. Inhibitor aids will also be needed if the bottom hole temperatures exceed 200–220°F. The K-reservoir is also classified as a moderately permeable to tight gas reservoir, which has a porosity ranging from 1 to 25 vol% in the higher porosity sections. These types of porosities, coupled with the natural fractures present in the zone, result in undesirably high leak-off rates. An acid fracturing treatment can increase the permeability of these fractures several thousand-fold, making leak-off control an even greater challenge.
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