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This paper describes a coiled tubing milling operation using fiber optic enabled coiled tubing and downhole tools for real time depth control and downhole monitoring of critical parameters. A description of the technology used, the job design, tool selection and execution of the job, the challenges encountered during the operation and the successful outcome are presented and discussed in the paper. The case history presented in this paper marks the first time that this particular fiber optic technology had been applied during a milling job worldwide. Coiled tubing milling operations can be challenging when precise depth measurement is critical. For the case history discussed in this paper the operator needed access to the production liner below the end of tubing with a BHA with a larger outside diameter than the inside diameter of the nipple installed in the tail pipe of the tubing. It was necessary to mill out this nipple profile while ensuring that other completion accessories above the nipple, including the production packer, were not inadvertently milled or damaged. Therefore, accurate depth control during the milling process was essential. Depth control was obtained with the real-time fiber optic CCL measurements. In addition, real-time pressure and temperature measurements were available from the fiber optic enabled BHA to monitor the milling parameters. The latest fiber-optic technology for coiled tubing including modules for CCL, temperature and pressure was used for the first time during a milling job. The data recorded, transmitted and integrated with the data acquisition software, created the ability to customize and optimize well intervention in realtime, and ensured that the required depth control precision was obtained, with precise control on the downhole milling parameters to optimize the milling operation.

This paper discusses the first successful in-Kingdom coiled tubing intervention in a well without conventional stripping-out of the well leading to significant cost savings, reduced risks, and compliance to Saudi Aramco environmental protection policies by adhering to a zero flaring initiative. Conventionally, wells are shut-in, secured, and stripped out (depending on the operation, stripped out refers to the disassembly and removal of directly connected piping, cathodic protection, and other production system components) in preparation for performing any high pressure coiled tubing (HPCT) interventions (to allow crane and HPCT units to spot and rig-up). Wells are then again re-manifolded to the production system. These stages consume a tremendous amount of manpower, cost, time, and production loss. Unfortunately, some wells have severe condensate loading issues, to the extent that they tend to die again, during shutdown (re-manifolding period) after the lifting operation. A new approach was required to be developed to avoid asset depletion in problematic wells. The new approach suggests eliminating the need for stripping out and re-manifolding by lifting the well while it is connected and flowing to the gas plant. Many challenges were encountered during this effort, including the limited space for spotting equipment around the well connections, well control, and well response monitoring. In addition, it was difficult to overcome the downstream pressure across the pressure control valve (PCV) to allow unloading the well under its own pressure drive. The operation served as a benchmark for future wells. The operation turned out to be a huge success in terms of cost and safety. The avoidance of strip-out, re-manifolding, testing package, and producing to the gas plant instead of flaring resulted in significant cost avoidance and reduction in production time. This paper will provide an insight on the reasons behind selecting this well as a potential candidate for the job. It will also shed light on the risk assessment aspects, both technically and environmentally, and the operational safety backup plan that was thoroughly discussed and implemented. In addition, the challenges faced throughout the whole process of selecting the well, conducting risk assessment, issuing the Management of Change (MOC), designing the rigless program, and finally commencing operations will be discussed to ensure obstacles in future operations can be minimized. At the end, lessons learned and recommendations will be shared to ensure that the highest levels of operational efficiency are maintained for similar cases in the future.

During the past two decades, fracturing stimulation has become a production driver for a much greater part of the oil industry worldwide. Because of the extensive reservoir formation types, fracturing scenarios widely vary from conventional to unconventional cases. Fracturing is one of the few options for commercial hydrocarbon production in some extremely tight reservoirs. Unfortunately, many of the tight formation scenarios achieve fracture inititation and/or extension only under extremely high pressure, thus frequently reaching mechanical forces close to the well completion limitations. Among the different techniques used, the controlled breakdown technique (CBT) helped significantly improve pump rates in some fracture initiation and injection conditions. This technique controls pressure, while considering the completion's mechanical limits. This paper discusses the process and appropriate conditions for CBT application and evaluates when it is convenient or even crucial to help enhance fracture initiation and development.

Maintaining oil production while both water cut and reservoir pressure are changing with time is a challenging task especially for fields equipped with artificial lift systems such as Electrical Submersible Pump (ESP). ESPs have a defined recommended operating range (ROR) that can reduce the flexibility of the system therefore a variable speed drive (VSD) unit is being used to extend the ROR. A surface choke is also another option to adjust the flow rates and control the ESP to operate within its recommended range. However, inefficient use of both options can be detrimental on the life cycle of the production system. High VSD Frequency will increase the motor speed which leads to increased power consumption. Low choke setting causes high hydraulic losses across the choke that can lead to wastes of energy. In oil fields equipped with ESPs, power consumption as well as ESP run life play a significant role in specifying the operation cost and economical life of the field. Therefore, it's essential to optimize the operation conditions of the ESP to optimize the operation conditions of the ESP through minimizing power consumption while maintaining a production rate that fall within the pumps ROR. Utilizing a technique that can quickly provide the best choke and frequency setting is a key to achieving more optimized operation in a dynamic field. This paper will discuss an in-house developed application that can calculate the minimum ESP motor operating frequency and the optimum choke setting point required to maintain the production rate at the minimum power consumption and lower motor speed. With the availability of real-time data from the surface and down-hole equipment, the optimization process was automated by collecting data and modeling surface equipment and ESP. this application is being used to optimize an entire field and the pilot test showed very promising results. A substantial 2000 KVA, which is equivalent to 1600 KWh, was saved by adjusting only 57 wells.

Development of gas resources in the Middle East is taking an increasingly higher priority, driven by the growing demand for gas based power generation as well as the motivation for replacing oil as furnace fuel as is the case in several middle-eastern countries. Such fields are often characterized by corrosion formation fluids including CO2 and H2S, formation solids and other non-hydrocarbon components. These associated components have the capability to adversely affect on compatability with well completions, design of production facilities, maintenance costs, reservoir assets and product sales value among others. The failure to have such information could represent much more risk than taking the decision to perform downhole sampling and laboratory analysis. Corrosion induced by the presence of sweet or sour gas combined with water production has led to major well integrity issues in some of these fields. Continuous monitoring and remedial programs have been implemented to issues either before or when they occur. Sacrificial tubing completions are deployed periodically inspected using corrosion monitoring tools and replaced based on established criteria. However, this process is associated with high monitoring, completion hardware, work-over and intervention costs. Several corrosion studies in the past have been conducted to understand the properties of water and the effect on the precipitation and deposition of ferric salts in order to devise a predictive model for onset of corrosion which is related to tubular lifetime with a view of establishing a reliable corrosion preventive strategy which precludes expensive monitoring or remedial work-over operations. In the past, produced water collected at surface was analyzed for chemical composition and PVT analysis but such results are inherently inaccurate due to the change in the chemical/composition and physical state of the water from downhole up to the surface. Hence there has been more focus on collecting "representative bottom-hole water samples". Memory based PVT samplers do offer this opportunity but suffer from the disadvantage of having to collect the samples "blind", quite often obtaining samples from the sump or coming back empty. This paper presents a novel technique and engineering accomplishment which enhances the PVT and water sampling capabilities at in-situ conditions on gas producers in combination with full production logging stack deployed on electric line, offering real time control of the sampling operation. The volume captured is adequate for proper broad fluid analysis; lesser quantities generate uncertainties which ended incorporated into the results. Field case studies are presented based on the early stage successful deployment of this technology and its impact on facilitating the recovery of representative formation fluid samples. Results of the fluid analysis have demonstrably improved the understanding of true water chemistry, which is a significant departure from earlier theories and contaminated measurements. Wells were sampled in order to carry out the risk assessment for corrosion and scaling tendency. The impact of the study on developing more effective well integrity and well intervention programs are also presented.to maintain the continuity of operations.

In acid stimulation treatments, acid will enter the most permeable or the least damaged zones. Most of the fluid will flow into the path of least resistance leaving large portions of the formation untreated. A critical factor to the success of an acid stimulation treatment is proper placement of acid so that all productive intervals are contacted by sufficient volumes of acid. The original stimulation fluid flow was altered to achieve uniform placement of treatment fluids during acid stimulation in candidate wells. Particle bridging technique utilizing self-degrading particulates of multiple grain sizes was utilized to achieve successful diversion and fluid placement across the entire interval of interest. Particle size distribution was calibrated for use with both near wellbore bridging across perforations and far field diversion inside wormholes and natural fractures. For self-degradable particulates to be successful as effective diverter, it should have accurate particle size distribution, therefore, a comprehensive well data analysis performed during design stage to recognize the opportunity for combination of far-field and near wellbore diversion systems for acid stimulation treatment. The combination of far-field and near wellbore self-degrading particulate diversion systems allowed the entire intervals to be treated evenly under matrix and fracture conditions, which is usually hard to achieve during acid stimulation treatments utilizing conventional chemical diversion systems, especially in cases where separate sets of perforations would need to be treated with a single stage. Evaluation of the diversion effectiveness was done by running temperature log immediately after the stimulation, which demonstrated satisfactory cool down effect across perforation intervals. This diversion technique was found to be more enhanced to effectively acid stimulate in high temperature carbonate reservoirs of Saudi Arabia. The utilization of self-degrading particulates of various grain sizes for far-field and near wellbore diversions during acid stimulation in high temperature carbonate reservoir was a unique approach and can be further optimized to resolve the challenges of multistage acid stimulation treatments.

Hydraulic fracturing activities in tight gas wells in Saudi Arabia have been exponentially increasing to meet domestic demand for natural gas. During each fracturing stage, up to 125,000 gallons of groundwater is currently being used. The need to reduce groundwater usage during fracturing treatments has been set as a priority, and alternative water sources for fracturing applications that can significantly reduce groundwater usage have been intensively explored. One such alternative water source is seawater as a base fluid for hydraulic fracturing. The primary challenge for this application is the tendency for scale precipitation due to the high sulfate content in seawater and its potential incompatibility with formation water. Without proper prevention and mitigation measures, this scale precipitation can induce formation damage and reduce the fracture conductivity. To minimize scaling tendencies, an in-house multidisciplinary team has performed extensive collaborative research to identify a scale inhibitor appropriate for Arabian Gulf seawater and formation water. Scale precipitation can be further mitigated by filtering the seawater with a nanofiltration system to dramatically reduce the sulfate ion as well as lower the calcium and magnesium ions. The successful application of seawater-based fracturing fluid in Saudi Arabia opens up the door to minimizing consumption of groundwater in hydraulic fracturing operations. Millions of gallons of groundwater could be saved and development of sustainable water resources could be achieved. This paper will describe the optimization of a scale inhibitor and fracturing fluid system, the selection of the nanofiltration system, and the first field applications of the seawater based fracturing fluid system in high-temperature gas wells in Saudi Arabia.

The objective of this paper is to highlight first worldwide implementation of coiled tubing (CT) compatible self-degradable fiber laden diverter for matrix stimulation treatment using enhanced high rate fiber optic real time telemetry system. The self-degradable fiber laden diverter has been used in bullheading acid stimulation treatments aimed to maximize reservoir contact and enhance gas production. Recently, the physical properties of fiber has been re-engineered enabling them to be pumped down coiled tubing to enhance diversion and stimulation effectiveness. Coiled tubing with fiber optic real-time telemetry has been utilized for many years in Saudi Arabia for matrix stimulation treatments and well interventions as it provides real-time bottom-hole parameters such as pressure, temperature, casing collar locator, gamma ray, tension and compression as well as distributed temperature sensing (DTS) to optimize fluid placement. The successes achieved with previously used 2 1/8-in. bottom-hole assembly (BHA) for coiled tubing with real time telemetry system offered the maximum rate of 2.0 barrel per minute (bpm), whereas this rate became a limitation to achieve the desired fiber concentration for diversion when fiber laden fluids were used. The low rate provision by 2 1/8-in. BHA led to the need of a new generation high rate 3.25-in. BHA to be used for coiled tubing fiber optic real-time telemetry system that can enable higher pumping rates, help in achieving the desired fiber concentration. For the first time in Saudi Arabian Carbonate reservoir, the novel fiber laden diverter was used during matrix stimulation treatment through 180 ft. perforated interval with new generation 3.25-in. bottom hole assembly (BHA) for coiled tubing fiber optic real-time telemetry system. The DTS used with the new generation coiled tubing high rate fiber optic real-time telemetry system helped in pre- and posttreatment evaluation. After successful high pressure coiled tubing stimulation using self-degradable fiber laden diverter with visco-elastic surfactant based acid system, the well performance exceeded expectation. The encouraging result was achieved by uniform stimulation coverage throughout the long perforation interval. The operation also proved the feasibility of using the new generation of fiber optic real-time telemetry system in challenging environment.

The majority of the gas-condensate reserves, currently being developed from fields located in southern Saudi Arabia, come from tight carbonate reservoirs, which require acid stimulation to achieve gas rate targets and field development objectives.Most of the gas producers drilled at the beginning of the gas development program were vertical completions, the majority of which were acid fractured and achieved excellent post-stimulation results. As the development scope expanded to areas with tighter reservoir characteristics, the majority of new wells were drilled as open hole single or dual lateral completions to achieve maximum reservoir contact (MRC). A significant number of these wells did not require acid stimulation, but many others did, either to increase productivity in underperforming wells, or to remove drilling induced formation damage. The most recent approach in the evolutionary process is to drill single lateral open hole horizontal producers and fit them with a completion designed for multistage fracturing treatments.This recent approach has allowed Saudi Aramco to effectively stimulate the entire horizontal section, optimize treatment designs, and achieve excellent post-stimulation results and high gas rates from wells drilled in even tighter reservoirs. This paper describes the historical trend leading to the selection and implementation of multistage fracturing technology as a fit-for-purpose technology to maximize productivity in long horizontal gas producers, and shares post-stimulation results achieved in typical wells drilled and completed throughout the different development phases.