Stimulation of a Deep Sour Gas Reservoir Using Gelled Acid

Rahim

et al. 2003

The Khuff formation is ideally made-up for acid fracturing because of the heterogeneous nature of the formation, which tends to support the created fracture conductivity. Various acid types were used to fracture this tight dolomitized formation including: 28 wt% regular HCl, emulsified acid, and in-situ gelled acid. In addition, several wells were fractured using 15 wt% HCl/9wt% formic gelled acids. However, based on production results and the large database of acid fracture treatments (more than 70 wells); it appears that there is a correlation between the acid type used and the lithology of the formation. An earlier study,1 which briefly examined this phenomenon, indicated that the emulsified acid might be more suited to low permeable zones. These low permeable rocks are predominately made up of limestone. Typically, changing the acid volumes, placement techniques, or pumping rates, has optimized acid fracture treatments by creating longer and wider fractures. However, we tend to ignore the effect of lithology in carbonate formations because we all believe that the rock interaction with the acid is not as sensitive as in sandstone formations. With this large database of acid fracture treatments, acid rock interactions were investigated to determine the relationship between lithology and acid type. This work involves correlating the designed treatment to the open-hole logs, core petro-physical data, analysis of hundreds of samples collected following acid fracture treatments, and production results. Introduction The Khuff formation is a deep gas carbonate reservoir that consists of dolomite and limestone sections underlying the giant Ghawar oil field in the eastern region of Saudi Arabia. The Ghawar field map is presented in Fig. 1, which includes the approximate boundaries of the two fields under study. The Khuff formation can have streaks of shale, anhydrite, or non-permeable intervals within the layer, which may constitute no-flow zone or fracture barriers. Figure 2 is a typical log indicating a Khuff well that is dominated with calcite, inter-dispersed with dolomite and shale stringers. This heterogeneity of the Khuff formation makes it an ideal candidate for acid fracturing even though the reservoir temperature is ranges between 280 and 300°F. Formation heterogeneity between the wells is significant with porosity intervals disappearing between offset wells.

Acid Fracturing of a Gas Carbonate Reservoir: The Impact of Acid Type and Lithology on Fracture Half Length and Width

Bartko

Rahim

et al. 2003

Acid Fracturing HT/HP Gas Wells Using a Novel Surfactant Based Fluid System

Al-Driweesh

Al-Muntasheri

et al. 2003

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.

Lessons Learned from Using Viscoelastic Surfactants in Well Stimulation

Samuel

2004

Viscoelastic surfactant systems are used in the industry for several applications. Initially, the application was focused on low friction and solids suspension (fracturing and CT-cleanout) characteristics of the fluid. In the last three years, the application of viscoelastic surfactants was extended to acid-based systems for carbonate stimulation. These surfactants have the ability to significantly increase the apparent viscosity and elastic properties of the treating fluids. This is due to the ability of surfactant monomers to associate and form rod-shaped micellar structures under certain conditions. Viscoelastic surfactant-based acid systems have been used in Saudi Arabian fields in matrix acid stimulation, and in leakoff control acids during acid fracturing treatments. These surfactants were used to provide diversion during acidizing of vertical, long horizontal and multi-lateral wells. They were used in sour environments where hydrogen sulfide levels reached nearly 10 mol%. They were also utilized in gas wells to reduce acid leakoff, and create deep fractures in dolomitic carbonate reservoirs (250–275°F). In addition, they were successfully employed to stimulate seawater injectors and disposal wells where the temperature was in the range of 100- 120°F. More than 150 wells (oil, gas, water injectors and disposal wells) were treated with viscoelastic surfactant-based acid systems. The acid was placed either by bullheading, by using coiled tubing with or without a tractor. In some cases, these treatments included stages of emulsified or regular acids. All these wells responded positively to the treatment. There were no operational problems encountered during pumping these acids even when low permeability reservoirs were treated. Because these acid systems do not contain polymer, there was no need to flow back water injectors. However, the spent acid in oil and gas wells was lifted from the treated wells in a very short period of time. Finally, wells treated with surfactant-based acid systems showed sustained performance for longer times than wells treated with other acid systems. Introduction Matrix acidizing and fracturing treatments have been used to enhance the performance of oil, gas and water wells for several decades. Water and acid-soluble polymers have been used in these treatments to increase viscosity and hence, enhance diversion during matrix acidizing treatments. High viscosity fluids are needed during acid fracturing treatments to reduce leak-off rate during acid injection into the fracture. Various acid systems were introduced to enhance acid diversion by increasing the viscosity of the injected acid. Depending on the viscosifiying agent, these systems can be divided into two main categories: polymer-based acids and surfactant-based acids. Acid-soluble polymers have been used to increase the viscosity of HCl, and to improve its performance.1,2 As the viscosity of the acid increases, the rate of acid spending decreases and, as a result, deeper acid penetration into the formation can be achieved.3 The addition of uncross-linked polymers to HCl improved acid penetration, however, acid placement did not significantly improve.4 Cross-linked acids were introduced in the mid 70's as was cited by Metcalf et al.5 These acids have much higher viscosity than regular acids or acids containing uncross-linked polymers. Two types of cross-linked acids are available. The first type consists of a polymer, a cross-linker, and other acid additives.6 The acid in this case is cross-linked on the surface and reaches the formation already cross-linked. The second type of cross-linked acid consists of a polymer, a cross-linker, a buffer, a breaker, and other acid additives, e.g., corrosion inhibitors and surfactants. The acid in this case reaches the formation uncross-linked, and the cross-linking reaction occurs in the formation.7 The polymer used in the in-situ acid systems is a copolymer of acrylamide. This type of polymer is soluble in HCl acid over a wide range of acid concentration (1 to 28 wt% HCl). The polymer is cross-linked using multi-valent cations, e.g., Fe(III) and Zr(IV), via the carboxylate groups.3,8 It has been reported that the polymer in this system forms a gel within a narrow pH range.7 As a result of gel formation, the viscosity of the acid increases in-situ and acid diversion can be achieved. This gel will improve acid placement in matrix acidizing, provide more uniform damage removal, and control acid fluid loss in acid fracture treatments.