Emulsified hydrochloric (HCl) acid has been used in both fracture and matrix acidizing of carbonate reservoirs to help penetrate deeper into the reservoir before spending. The emulsion stability and adequate corrosion inhibition are critical requirements of this blend, which are challenging to accomplish using emulsified acids of high HCl acid concentration (>26%) at high temperatures (>250°F) because many corrosion inhibitors used in the industry can severely affect emulsion stability by interacting with the emulsifier. The requirement of other additives, such as iron-control additives, surfactants other than the emulsifier, H2S scavengers, etc., can further add to the challenges. This work presents the laboratory optimization of 26% emulsified HCl-acid blends for use at temperature ranges between 250 and 300°F. Quaternary ammonium salt based Inhibitor I-C and a propargyl alcohol based Inhibitor I-N were used in this study. One inorganic halide based (IN-H) and one organic acid based (IN-O) intensifier were used to achieve adequate corrosion inhibition. A single commercial blend of surfactants was used for all the tests. Based on the high-pressure high-temperature (HPHT) static corrosion tests, Inhibitor I-C performed better than Inhibitor I-N at 275°F. However, Inhibitor I-C was found more damaging to emulsion stability than Inhibitor I-N. At 250°F, the performances of both inhibitors were comparable. A common misconception that prevails in the industry is that a stable emulsified acid can ensure a successful acid job without (or with a very little amount of) corrosion inhibitor. It was clearly evidenced during this study that the emulsion stability alone does not ensure the protection of alloys from corrosion. Using a suitable corrosion inhibitor in appropriate concentration is as equally important as emulsion stability for successful completion of an emulsified acid job without encountering severe corrosion problems.

The carbonate gas producing zones of the Ghawar field have been impacted by extensive FeS scale deposition, reducing overall gas production and significantly increasing risks of well interventions. Previous remediation included the use of workover rigs, which can be costly because of the time necessary for workovers and lost production. H 2 S levels (2 to 5%) found in the reservoir also contribute to higher costs and risks when using workover rigs.A chemical solution was also considered, but the FeS could not be 100% dissolved with HCl and the chemical reaction generated large amounts of H 2 S in addition to existing high levels of H 2 S in the reservoir. This poses a safety concern with the returns at surface along with potential corrosion of the coiled tubing (CT) and completion. Therefore, the safest and most economical method was deemed to be mechanical descaling with CT.This paper discusses two wells where mechanical descaling was applied using CT. Each well involved four major challenges that included low reservoir pressure, increased reservoir temperature, horizontal openhole completion, and scale with high specific gravity (3.7 to 4.3). The low reservoir pressure required pay zone isolation to allow for returns to circulate out the heavy scale and to minimize fluid losses to the formation. The fact that the wells had long, openhole sections created another challenge for isolation and cleanout. With a bottomhole temperature (BHT) as high as to 310°F, the operational envelope of temporary chemical packers in combination with loss circulation materials (LCMs) to isolate the openhole section had to be expanded. Following mechanical descaling with CT, the final challenge discussed in this paper is the process to clean out the LCM in the horizontal openhole and bring the well back to maximum gas production using pinpoint stimulation techniques.

As the world's demand for natural gas hits new records, technology developers and researchers work interactively to provide new technologies that support gas production and supply. Among these technologies come isolation plugs: mechanical and chemical. Chemical plugs have two main advantages over mechanical plugs. First, chemical plugs enable more flexible movement for Coiled Tubing (CT). Second, chemical plugs are easier to remove once unneeded using acid. Fluid systems used as diverters and temporary plugs in stimulation and work-over operations, are mostly polymer-based fluids that generate less damage to the formation and can hold higher differential pressures. The use of this technique has minimized the need for mechanical packers, bridge plugs and mechanical diversion techniques. One application for chemical plugs is selective zonal stimulation, where a coiled tubing and chemical plug are used in multi¬zone gas wells to selectively stimulate zones of interest. This paper outlines the first, in Saudi Arabia Gas Fields, successful deployment of a chemical plug— using CT — to stimulate the lower interval while isolating the upper producing interval. In addition, the plug's key characteristics, optimum rate and amount are addressed. Analysis of the post-treatment results, production rate and flowing wellhead pressure, demonstrated a very positive productivity.

For the past decade, Saudi Aramco has been successfully exploiting tight gas sandstone formations. These formations are routinely hydraulically fractured to enhance gas production, but as the development of the existing fields continues into deeper formations the exploration of new reservoirs emerges. New challenges are now being faced especially, considering that higher temperature is being encountered and the fracture fluids currently being used (based on borate crosslinker) are not stable enough to tackle the extreme conditions. Metal-crosslinked fracture fluids have long been the most popular class of high viscosity fracturing fluids. Primary fluids that are widely used are titanate and zirconate complexes of guar, hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar (CMHPG), or carboxymethyl hydroxyethyl cellulose (CMHEC). Zirconium-delayed CMHPG are typically used for high temperature applications. These types of fluids provide high temperature stability with low polymer loading with the added benefit of salt compatibility. The proppant transport capabilities of the metal-crosslinked fluids are excellent. Zirconiumdelayed CMHPG fracture fluid is currently the preferred fluids due to its extraordinary stable characteristics for bottom-hole temperatures (BHTs) up to 375°F. This paper addresses the research, lab testing and successful application of a metal-crosslinked fluid used for fracturing operations of a high temperature (312 ~330 °F) tight gas reservoir in Saudi Arabia, with its post-treatment evaluation to optimally develop these reservoirs in harsh bottom-hole conditions.

In recent years, high-pressure/high temperature (HPHT) sour gas producers in Saudi Arabia, completed with two or more open hole laterals have faced several operational challenges, specifically for well intervention and stimulation procedures. Several lessons learned throughout the timeline of the operations and the procedures have evolved to optimize and enhance the results. Drilling and completing open hole multilateral gas wells in carbonate reservoirs is a common practice in Saudi Arabia to maximize reservoir contact and increase the recovery of reserves. The majority of these wells require coiled tubing (CT) conveyed acid stimulations to remove drilling damage and enhance productivity after the drilling process. The challenging conditions encountered during the aforementioned CT interventions include: extended open hole horizontal sections with large hole diameters affecting the ability of reaching the deepest zones of interest; pumping 26% inhibited hydrochloric (HCl) acid for extended periods of time at high temperature with extremely high H2S and CO2 content, generating a very corrosive environment for all tubulars involved in the operation; wellbore instability issues inducing obstructions that prevent the accessibility to open hole sections; accessibility of alternate laterals, especially after the first lateral has been stimulated; optimum rate and pressure to achieve the desired pressure drop across hydrajetting nozzles; and natural fractured reservoirs that promote fluid losses affecting the optimum fluid placement control. The inclusion of friction reducers for CT extended reach applications, combined with the introduction of larger outer diameter (OD) CT, have improved the access to the zones of interest. The redesign of the isolation sleeve for the jetting tool has reduced the number of required trips when obstructions have been encountered, including the improved use of steering tools to access target laterals. Further laboratory analysis, specific to the HPHT sour conditions of these wells, has been performed to minimize corrosion in the completion and the CT, and to optimize the pumping schedules to target the pay zone. This paper provides details about field experiences and lessons learned with this type of stimulation, and describes challenges faced and the engineering solutions developed to overcome them.