Hydraulic fracturing technology is widely used to facilitate and enhance the gas recovery process from conventional and tight gas resources. Tight gas or unconventional reservoirs, that include very low permeability sandstones, carbonates, or shales, cannot be economically produced without hydraulic fracturing. Recently, much progress has taken place in the overall hydraulic fracturing procedures and the field implementations of advanced stimulation technology have produced good results. The proper selection of well trajectory, gel concentration, polymer loading, proppant type/size and concentration, perforation methods, locations for packer and frac port placement in a multistage fracturing assembly, number of fracture stages to cover the net pay, etc., have all contributed to successful stimulation and improved gas recovery. Even though stimulating gas reservoirs has become a routine application and much experience has been gained in this area, not all treatments are straightforward without problems and challenges. Unless a stimulation treatment is carefully designed and implemented, the post-stimulation results in moderate to tight reservoirs may not be encouraging, and can easily fall below expectation. The most essential step to close the gap between expected results and actual well performance is to understand reservoir characteristics and its potential to produce at a sustained rate after a successful fracturing treatment. Overestimation of reservoir flow capacity and achieved fracture geometry will also over-predict well performance. This paper addresses the importance and impact of detailed reservoir characterization and superior stimulation processes on final well performance. Several field examples from Saudi Arabia’s gas reservoirs are presented in the paper showing the value of effective well planning, reservoir characterization, application of hydraulic fracturing, and proper cleanup. The paper also illustrates the impact of drilling trajectory and wellbore reservoir connectivity on the proper placement of desired hydraulic fracture treatments and sustained gas production.
Hydraulic Fracturing for sand control techniques in screenless completions have been successfully attempted, predominantly in oil wells, by operators the world over; whereas, frac-packing has rapidly become the preferred option for high rate gas wells in highly permeable reservoirs. Saudi Aramco is currently undertaking one of the largest gas development projects in the world comprising a large number of new deep wells, four world-class gas plants, and massive development of new infrastructure. The Jauf reservoir, one of several forming part of the gas development project, is a sandstone with unique characteristics, because it exhibits low to moderate permeability but high sanding tendency caused by high degree of rock unconsolidation under high 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. This paper presents the results of a performance driven process, successfully implemented by Saudi Aramco in partnership with Schlumberger, which has achieved sand and solids free gas production in a score of wells treated to date. A detailed description of the combination of effective techniques applied as part of the process is provided, and lessons learned throughout the fracturing campaign are shared. The solids free gas production rates achieved in the wells discussed herein range from 10 to 50 MMSCF/D at high condensate yields. All wells were repeatedly cycled and, in some cases, limitation on the testing equipment used prevented testing wells at higher solids free rates to achieve full potential. Introduction Saudi Aramco embarked on an aggressive non-associated gas reserves development program and expansion project in 1995. This project encompasses the drilling of new wells, development of the known reserves in the Ghawar field and new fields, construction of new facilities, and upgrade and expansion of existing ones. The new Hawiyah gas treatment plant was recently commissioned with a processing capacity of 1.6 BSCFD, and the new Harad gas plant, with the same processing capacity, is scheduled for completion in mid-2003. The majority of wells drilled to feed the Hawiyah gas plant exhibited reservoir characteristics, which clearly indicated that stimulation would be required in order to meet production targets. Furthermore, core and open hole test data from the first drilled wells provided ample proof of the highly unconsolidated nature of the rock, thus giving the Jauf unique reservoir characteristics: deep, low to moderate permeability, and high sand production volumes if no appropriate control is used. The first stimulation treatment was pumped in early 1999 in a well completed with 5-1/2" tubing in 7" liner. Reservoir quality of the well is good with low Young's Modulus in several layers throughout the net sand. A two-stage fracture was pumped in this well. A 60' interval with 60° phasing was perforated for the first stage and a 20' interval for the second stage. A large pad and 20/40 ISP only were pumped at a maximum concentration of 8 ppa., so no tip screenout was desired, and no flowback control method was used. No recording of recovered solids was performed, so it is not possible to ascertain total solids recovered, but a large mass of predominantly formation sand was recovered throughout a 55 day flowback period, at which time, the well achieved a clean rate only when it was chocked back. Therefore, the treatment was rendered ineffective in controlling solids flowback.
Sand control has been a challenge to the petroleum industry since oil and gas was produced from weakly cemented sandstone formations. Several techniques have been applied;restricted (critical) production rate,screen and/or gravel packing,sand consolidation,FracPacking,oriented and/or selective perforation, andcombination of any of the above. Sand formations may fail in compression, tension, and cohesion that trigger sand production. The compressive failure occurs during drilling where the rock cannot withstand the new stress field and/or the cementation materials have deteriorated from mud filtrate exposure. The calculation of mud weight to prevent compressive failure will be presented in this paper. Additionally the failed zone is usually oriented in the direction of minimum horizontal stress which can be avoided during perforation by orienting the perforation tunnels in the direction of maximum horizontal stress. During completion the cementation materials should be protected from completion fluids. During production a pressure drawdown is established for a given production rate. This pressure drawdown may cause rock failure in tension or cohesion (erosion) leading to sand production. The near-wellbore pressure is caused by skin damage due to reduced permeability, stressed region, convergence flow, and partial penetration. This paper presents a model to determine the critical pressure drawdown based on relating the near-wellbore pressure drawdown to the tensile and cohesive strengths of the formation. Hydraulic fracturing, referred to as FracPack, may be applied to alleviate the near-wellbore pressure drawdown below the critical value that causes sand failure. Two fracture parameters are designed to achieve this goal; fracture length and fracture conductivity. This paper presents a design criterion to determine these parameters to optimize a FracPack design for sand control. Examples from a field in Saudi Arabia will be used to validate the application of controlling sand production using screenless FracPack completion. In these wells a FracPack treatment alone controls sand production. The multirate test used in these wells and the FracPack design for fracturing treatments will be presented. Introduction Sand production has historically been a problem associated with soft or poorly consolidated formations. The result is usually lost production due to formation sand and fines plugging gravel packs, screens, perforations, tubular, and surface flow lines or separators. In addition to damaging pumps or other downhole equipment, erosion of casing and surface facilities may also occur. Sanding problems may actually cause loss or recompletion of a well due to casing and/or hole collapse. The methods applied to minimize the effect of sand production include critical production rate, gravel packing, sand consolidation, FracPacking, oriented and/or selective Perforation, expandable sand screen, or a combination of these methods. Completion methods are selected based on sand characterization and failure mechanism. Laboratory testing and mathematical models used for sand prediction are selected based on sand characterization. FracPac completion has been replacing gravel packing in many petroleum reservoirs. However FracPack with a screen in hole, is also widely applied. This paper will discuss the process of sand control from the time a given formation is exposed to man's disturbance and will sicuss sand control during drilling, completion, and production.
Among the various design and operating parameters, efficient acid stimulation in deep carbonate reservoirs depends on the placement technique, injection profile and treatment composition. Unlike acid fracturing, matrix acidizing creates several conductive flow channels with substantially higher conductivity compared to the reservoir rock. These conductive channels transport reservoir fluids from the formation matrix directly into the wellbore overcoming both low permeability and near wellbore damage. The treatment composition, and more importantly, the injection technique to maximize the number and depth of penetration of these conductive channels, are among the most predominant design criteria of successful carbonate matrix acidizing especially in a high-pressure and high temperature environment. The Permian Khuff carbonate reservoir in the Ghawar structure of Saudi Arabia produces nonassociated gas and condensate. The reservoir is characterized by heterogeneous porosity and permeability distribution extending in both areal and vertical directions with varying in-situ stress contrast along the structure extension. Due to the reservoir complexity, each well requires individual assessment to determine the optimum completion design necessary to achieve efficient matrix or fracture acidizing treatment. Some wells may need simple matrix acid treatment, while other wells may need open hole multistage (OHMS) fracture stimulation. Results demonstrate that OHMS completion was required to successfully stimulate all net pay intervals. This paper presents an overview of Saudi Aramco’s efforts to evaluate various stimulation methods used in the Khuff reservoir and highlights an optimal carbonate stimulation technique for certain reservoir conditions via the first trial test application of a limited entry OHMS completion for effective stimulation. The technique uses a system that is designed to run as part of the production liner and provides mechanical diversion at specified intervals, thereby allowing multiple matrix acidizing treatments to be effectively placed in the target zones. The technique was applied recently for the first time in Saudi Aramco’s gas program and the details are discussed in this paper.
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