One of the major challenges to maximizing recovery of reserves is that every oil or gas reservoir rock is more or less heterogeneous at all scales (micro, mega, and pore) which leads to disproportionate production and injection outcomes. Generally, the higher the level of reservoir heterogeneity the more difficult it becomes to achieve maximum fluid distribution or conformance. Improving conformance in a non-homogenous material such as a hydrocarbon reservoir inherently means improving flow through lower permeability regions. Ideally, during a conventional well stimulation using a treatment fluid such as acid, we wish to move the fluid through the majority of the rock volume but the physical constraints of fluid flow negatively impact that ideal outcome. Dynamic fluid pulse technology provides for high inertial fluid momentum which improves the flow efficiency of fluids injected into the wellbore, the near wellbore region, and the reservoir. The nature of fluid displacement energy ensures that pulsed fluid will penetrate the matrix proximal to where the tool is placed thus achieving enhanced fluid distribution. Prior to a stimulation operation a dynamic mathematical model associated with fluid pulse technology is employed to generate a precise well program (pumping schedule) to maximize the contact volume of the treatment fluid along the completed interval. Compared with conventional stimulation dynamic fluid pulsation has been demonstrated to bring significant financial benefits to well stimulation without impacting results including: reduced chemical costs; improved post-stimulation sustainability; and, better overall poststimulation well performance as a greater volume of the completed interval hence matrix is contacted by the treatment fluids.

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With the increasing complexity of well completion, the rigless intervention work is becoming more challenging. Conventional techniques are no more adequate to access long horizontal wells to perform intervention work such as acid stimulation, logging, and zonal isolation. This paper will describe the process of using a downhole coiled tubing (CT) tractor to access a horizontal open hole (OH) extended reach power water injector (PWI) well in the Ghawar field, the world's largest oil field, to perform a huge matrix acid stimulation job. The volume of the treatment is considered one of the largest for a PWI and the first utilization of a CT tractor in the Ghawar field. The paper will review the process of candidate selection, job design and planning, execution, and results and post job evaluation. The job set an excellent example of advancement in intervention technique accessing long horizontal wells beyond the normal reach of coiled tubing. In this job, the CT tractor has increased the reach of CT by 54% and a world record of coiled tubing tractored interval in horizontal OH of more than 5,000 ft was achieved. The injection rate of the stimulated wells was increased by more than twofold. Introduction The giant Ghawar field, located in the Eastern Region of Saudi Arabia, is more than 200 km long and 40 km wide of carbonate reservoir with continuous oil column, Fig. 1. The production from the field was started in 1951 from the northern part and thereafter the field was developed toward the southern tip with the last increment put on stream in 20061. Reservoir characterizations change along the north-south lateral with the southern part known for lower reservoir quality dominated by low permeability fractured formation. To maximize recovery of oil from this unique reservoir, peripheral water injection was started in 19662. As the development reached the southern part of the Ghawar, the reservoir quality dictated the necessity to utilize the latest advancement in drilling technology including long horizontal, maximum reservoir contact (MRC), real-time geosteering, and I-Field initiatives. These complex completion wells present a challenge to production engineers to riglessly access them in order to perform intervention work to enhance performance or remedy downhole problems. Due to tightness of reservoir formation combined with formation damage, matrix acid stimulation jobs were deemed necessary to improve injectivity supporting the reservoir pressure in this part of the field. In extended reach horizontal wells, bullheading of treatment fluid is not efficient due to the nature of this fractured reservoir and a coiled tubing unit (CTU) should be used to provide uniform distribution of the acid across the horizontal treatment interval. Field experience indicated that accessibility of a CTU in horizontal wells is limited due to increased friction generated when the pipe starts to get helically buckled and finally reaches a lockup point where the total down acting forces are no more sufficient to move the CT pipe further in the well. This limits the capability to distribute the treatment across the horizontal section. Different techniques have been used to overcome this limitation of CT to perform intervention work such as using large outside diameter (OD) coiled tubing, downhole vibration tools, and friction reducer chemicals3, 5. Well Completion and History The well was drilled and completed as an extended reach horizontal OH PWI to a total depth (TD) of 17,716 ft and true vertical depth (TVD) of 7,690 ft, Fig. 2. The 6 1/8" OH was drilled from 8,322 ft to TD. The well was completed with 7" completion packer and a tail pipe assembly at 7,358 ft with the end of the tail pipe at 8,794 ft, leaving 8,922 ft of horizontally exposed reservoir formation with a maximum inclination angle of 93°. The average reservoir porosity is 10%. The objective of this completion is to cover the anhydrite formation in the 6 1/8" OH below the 7" liner to the top of the injection formation, Fig. 3. The decision to set the packer was taken during the drilling course due to unexpected formation development and dipping where the setting of the 7" liner was found above the injection formation leaving the anhydrite formation exposed.

Recent advances in horizontal drilling technology have allowed drilling longer horizontal sections in the reservoir more efficiently and economically. While operators benefit from the well-known advantages of horizontal drains, such benefits cannot be maximized during the lifetime of the well without a viable well intervention means for well service and monitoring operations. Coiled tubing has been recognized as an effective technique for such interventions but with limitation on the total length that can be accessed especially in extended reach wells. This paper summarizes the utilization of innovative coiled tubing Tractor technology to improve coiled tubing accessibility in long horizontal wells . Introduction The paper discusses the aspects of well intervention using coiled tubing (CT) and coiled tubing tractor technology on four (4) open hole horizontal water injection wells and one (1) cased hole oil producing well. The results presented show that the use of a coiled tubing Well Tractor combined with coiled tubing along with proper well selection, design and planning can result in a significant improvement in Well accessibility both in cased hole and open hole . Well Accessibility with Coiled Tubing For a well to be accessible with coiled tubing, the coiled tubing need to be run to the end of the horizontal section and no "lock-up" should happen before reaching TD. Lock-up occurs when no weight can be transmitted to the end of a coiled tubing and hence no progress into the horizontal section is possible. Coiled Tubing simulation software is available that can predict the depth at which this lockup is reached and whether it will occur. Such simulations are often used in the planning stage of a coiled tubing Intervention to decide on the type of coiled tubing pipe to be used (diameter and thickness). The following factors are taken into account in the simulation : Well trajectory, coiled tubing pipe variables (OD, thickness, strength, length), Diameter (s) in the wellbore, friction coefficients (cased/openhole), Well fluid type, temperature, pressure, and wellhead flowing conditions. Many techniques can enhance coiled tubing accessibility into the wellbore : The use of larger pipe, pipe straighteners, vibrating tools, pumping of Nitrogen, pumping of friction reducers or a combination of the above. A lot of literature has been published and is available about these techniques. Figure (1) shows coiled tubing Lockup depth using a typical output of a Well Intervention simulation program [refer to point A on the graph]. This is the "theoretical" Lockup point. Actual Lockup point can only be found when the coiled tubing is run into the hole. The advantage of using a coiled tubing Tractor at the end of coiled tubing is that it provides a concentrated downhole force that can delay or prevent lockup by "pulling "the coiled tubing from its end. This often results in improving well accessibility on extended reach wells. It is thought that when the CT locks up, a spiral type of form takes place at the end of the coiled tubing section; having a concentrated point load acting at the end of the coiled tubing will make this event unlikely thus improve the accessibility. Figure (1) shows the new lockup depth predicted by the well intervention Simulation program [refer to point B on the graph] after applying a concentrated force of 4000 lbs by the Tractor at the end of the coiled tubing as per the well intervention simulation.

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