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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDue to the complex nature of carbonate reservoirs, reservoir characterization often leaves many uncertainties. Finding the right balance between risks associated with these uncertainties and optimum stimulation makes acid fracturing and matrix acidizing treatments challenging. The stimulation objectives become even more difficult in highly slanted, layered, naturally fractured reservoirs exhibiting high permeability contrast. In this environment, adequate fluid diversion and leak-off control have always been the key design elements for stimulation. Achieving diversion and leak-off with a degree of control to make treatments applicable to a wide range of reservoir uncertainties presents challenges.A novel, polymer-free degradable diversion system has been in use for the last three years in the largest carbonate reservoirs of the world, namely the Khuff formation in Saudi Arabia's Ghawar field. The self-diverting fluid combines viscoelastic surfactant in HCl with degradable fiber technology. The fluid develops viscosity as the acid spends, while the fibers bridge across perforation tunnels and fissures to form a filter cake. Because the fibers completely degrade with time and the spent fluid breaks when it comes into contact with hydrocarbons or solvents during flowback, the fluid temporarily limits injectivity into thief zones without damaging the reservoir.More than 50 wells have been stimulated with this fluid system covering a wide range of single and multi-stage matrix acidizing and acid fracturing treatments. The controllable nature of diversion from well to well and on-the-fly adjustment capabilities of the fluid system have successfully ensured stimulation performance despite the uncertainties of carbonate reservoirs in Saudi Arabia. In essence, this novel fluid became the standard insurance policy for stimulation treatments of carbonate formations where the permeability models are inherently underestimating the contrast due to difficulties of placing natural fractures and quantifying their impact.

The increasing demand for oil and gas resources to support the worldwide development plans means that the petroleum industry is always actively engaged in exploring new frontiers in drilling and production, including tight multilayered reservoirs. It is becoming evident, more than ever, that producing the most oil and gas out of the drilled reservoirs is an absolute necessity. Accordingly, completion techniques have presented themselves as a crucial well construction parameter and a key to optimally producing wells. Several completion techniques have been exhaustively trial tested in Saudi Aramco to determine the most successful completion mode for each reservoir. Among those various techniques, open hole multistage stimulation has demonstrated superior performance in minimizing skin damage and maximizing reservoir contact through efficient propagation of fracture networks within the rock matrix. Overall, the production results from wells completed using open hole multistage stimulation systems -as deployed in the tight gas fields of Saudi Arabia -have been very positive. Of the approximately 40 wells where this new technology was utilized, the majority of the wells have met or exceeded the pre-stimulation expectations for gas production. Various multistage open hole completion systems were run over these 40 wells and the production results varied. This study highlights these systems and discusses their impact during the fracturing operation and the final stabilized well production. This study will also present some case studies in multistage fracturing operations and investigate the operational impact on productivity enhancement. Following the lessons learned and best practices from these experiences, with correct implementation, the findings from this study should increase the probability of having a more successful multistage stimulation job from a productivity standpoint. TX 75083-3836, U.S.A., fax +1-972-952-9435

Saudi Aramco has been conducting a successful fracturing for sand control strategy in high pressure/temperature high gas rate screenless completions in the Jauf sandstone, which exhibits high sanding tendency in certain zones throughout the reservoir. The strategy combines a number of techniques, including indirect fracturing from oriented perforated thin consolidated zones, tip screenout design, use of a combination of resin coated proppant (RCP) with fibers, forced closure, and a carefully controlled flowback procedure. Although solids-free high rate gas production has been achieved in the majority of wells for which the strategy has been implemented, a reduction in fracture conductivity in the form of positive skin has been detected in several hydraulically fractured wells in which pressure buildup tests have been conducted. Part of this negative effect results in all likelihood from partial perforation effects, given that the interval from which a fracture is initiated is usually perforated in high Young's Modulus rock and limited to 30–40 feet. Thus, the fracture is initiated away from the high sanding tendency zones and extended into such zones. The other main component for the positive skin are the fibers used for proppont flow back control purposes since it is well known through extensive industry testing that the combination of resin coated proppant and fibers can reduce fracture conductivity in treated wells. Lab testing aimed at identifying potential conductivity reduction mitigation techniques, while maintaining the ability to achieve effective formation sand control, showed that the combination of two new additives, when mixed with proppant, was able to achieve both key requirements. Hence a suitable candidate was selected for a field trial. This paper discusses the results of the first field trial of the additives tested as an alternative to the resin coated proppant/fibers mixture and the lessons learned from the trial. A direct comparison between the well treated with the new additives and an offset well previously treated with resin coated proppant and fibers, showed that the well treated with the new additives yielded better productivity despite the fact that its kh was only 1/3 of the kh of the offset well. A post-treatment pressure buildup tests was conducted in each of the wells for a valid comparison. Introduction An aggressive program to develop non-associated gas reserves in the Ghawar field has been carried out by Saudi Aramco for the past five years. As a result of this program, significant new sweet gas and condensate reserves have been added in the Pre-Khuff reservoirs. The Early to Middle Devonian Jauf formation is the dominant Pre-Khuff reservoir in the Central and Northern Ghawar field. The Jauf formation consists of shallow marine sands with excellent reservoir quality, in spite of being deep. The Jauf reservoir is a sandstone with unique characteristics, because it exhibits low to moderate permeability and a high sanding tendency caused by high degree of rock unconsolidation under high reservoir pressure and temperature conditions. Frac-packing was considered as a potential sand control technique early during the planning phase, but the relatively low permeability encountered upon testing of the first Jauf reservoir producers clearly indicated that highly conductive, long half-length hydraulic fractures would be required to meet gas rate project targets. Hence, the decision to pursue fracturing for sand control techniques with screenless completions techniques was made. Following the early disappointing results to control sand production, a successful hydraulic fracturing strategy was designed and implemented. The strategy combines a number of techniques such as indirect fracturing, tip screenout design, use of resin coated proppant, resin coated proppant and fiber, etc. Almost 40 wells have been hydraulically fractured successfully for sand control and production enhancement. Some of these wells have achieved a solids-free gas production rate of up to 50 MMSCFD with high flowing wellhead pressure. A reduction in fracture conductivity in the form of positive skin has been detected from pressure buildup tests conducted in a number of fractured wells. The first field trial of the new additives showed positive results in mitigating this low fracture conductivity and eliminating the positive skin.

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.