A gel-based, crosslink-diverter system has been the fluid of choice for a wide range of temperature applications for carbonate acidizing treatments in Qatar. Recent field experiences with acidizing low-temperature wells (100 to 140°F) indicated the need for a chemical diverter system that develops viscosity rapidly enough to divert acid in a continuous pumping stream.A viscoelastic surfactant-(VES) based acid-diverter system was selected for a trial treatment because of its attributed phenomena of viscosity generation. Viscosity development for this system is a function of divalent cations generated as a result of HCl acid reaction with carbonates. Laboratory tests were performed to evaluate a viscosity profile for viscosity development versus acid spending. It was established that using 15% HCl mixed with the VES system would provide sufficient reaction rates at these low temperatures to generate an adequate amount of the divalent cations for rapid viscosity development. Formation fluids act as breakers for the VES gel. Treatment guidelines were developed based on the sensitivity of VES systems to iron content, corrosion-inhibitor concentration, and incompatibility with emulsified acids.Field application of the system showed promising results by providing better acid diversion for these low-temperature wells compared to the gel-based crosslink diverter. Downhole-pressure plots confirmed the rapid viscosity development as predicted from the lab tests. Field mixing and pumping guidelines were developed for further application of the system based on the learning from these field applications.This paper presents various guidelines for successfully using the VES-based diverter system in low-temperature wells for effective acid diversion. Lab-test procedures and results to serve as a guideline for such applications are discussed. Case studies are shown to demonstrate the effectiveness and success of carbonate acidizing treatments using VES systems for diversion in lowtemperature wells.

Technological advances and improved operational efficiency have made unconventional resources around the globe far more lucrative for producers. The challenge in recovering hydrocarbons from unconventional resources is low permeability, making it essential that a cost-efficient fracture-stimulation treatment program be performed. However, while the wells being completed are economical, are operators truly capitalizing on their full potential?The process of fracturing unconventional reservoirs has remained virtually unchanged in recent years. Stimulation treatments are pumped at high rates through multiple perforation clusters over a large interval and isolated using mechanical plugs. This poses several problems:Uncertainty of the number of fractures created. Uncertainty of proppant placement into fractures. Costly and time-consuming recovery from screenouts. Pumping plugs results in overflushing the near-wellbore. Treatment changes cannot be seen at the perforations until a casing volume is pumped. Increased cost, footprint, personnel, and hydraulic-horsepower (HHP) requirements.This paper presents a high-rate coiled tubing (CT) fracturing technique that enables customized fracture treatments to help maximize stimulated reservoir volume (SRV) by manipulating flow rate and proppant concentration at the perforations in response to reservoir pressure. Therefore, every gallon of fluid and every pound of proppant can be used to effectively stimulate the formation. Recovery from screenouts is fast because of having coil in-hole, but the functionality of the process enables screenouts to be avoided all together. At the end of the treatment, the well is simply cleaned out, and the entire operation is completed with only one trip in hole and with no plugs to be drilled out. These benefits combined can maximize return on investment for the operator. This paper includes a side-by-side comparison of this technique with a conventional fracturing treatment, weighing risk, stimulation effectiveness, operational efficiencies, and cost savings.

The long term development from four artificial islands of this giant offshore field in the United Arab Emirates (UAE) is requiring longer and longer ERD wells. This can only be achieved by drilling higher angle, higher departure and increasing lateral lengths. Horizontal departure ratios have increased from 2:1 to 3:1 and will, before the development has finished approach 4:1. Maximum Reservoir Contact (MRC) lateral lengths at the beginning of the development were planned to average 10,000ft but are already being lengthened to 20,000ft, and beyond. This paper describes the many challenges that have arisen and have been successfully overcome to enable deployment of 6 5/8" horizontal lower completions of lengths up to 20,000ft into wells that are greater than 30,000ft MD. These challenges have been surmounted through the use of proprietary in-house software, leveraging partner resources and global experience, close collaboration between drilling, completion and field development teams, new technology equipment development and deployment methodologies. Several case histories will be presented and discussed at length in this paper. These will focus on specific aspects for each of the wells such as the; high strength liner connections, high load liner running tools, reservoir drilling fluid composition, swellpacker design, use of drillpipe or casing swivels, centraliser type and the effect of dog leg severity in the long reservoir lateral.

Driving efficiency to ensure cost and risk reduction in well operations is paramount for any operating company; to achieve this, the main objective was to implement a continuous improvement process that measures performance to then improve it, acquiring lessons learned and finally implement new technologies to reduce non-productive time, invisible loss time and push the technical limit to the limit. The first step was to measure the current performance to determine average and best references to compare against. The drilling operations and engineering teams defined KPIs for each well type and respective sections and activities involving all levels of the organization including every individual, ensuring effective communication inclusive of Rig Crew and Service Providers. The initial KPIs were defined, discussed, validated and agreed by both operations and engineering management, all engineers were informed and challenged to measure their performance against KPIs. Once new records were achieved, a workflow to document best practices initiated, once identified, validated and documented, becoming the new standards. Similarly, once average performance was not achieved, a ‘Lessons Learned’ workflow was initiated. Aiming to get the team engaged a communication protocol of the Highlights and Lowlights was put in place, including recognition during operations meeting and emails. The primary results of the deployment of this initiative include the delivery of a 10% additional well count compared to the initial year's plan. An overall improvement of the overall Drilling and Completion Performance was also noted. An important improvement of the overall Rate of Penetration (ROP) was observed, as one of the key performance indicators. It was also notice a considerable reduction of the Flat time. New practices for losses mitigation in hazardous areas were stablished. The lower completion design was enhanced. The upper completion design and utilize Dual Hydraulic Packer in Oil producer well was optimized. Finally, the 1st Maximum Reservoir Contact Well was completed for two of the three Fields in the Team. The added value achieved by the implementation of these innovative practices includes the implementation of the KPI Gauges as a visual instrument to be used on daily operations meeting by the engineers and management, to quickly and effectively understand performance and improvement in multiple dimensions. Additionally, the implementation of a continuous improvement mind-set, focus in introducing changes gradually instead of radically to ensure a soft and solid adoption embraced by all team members. Finally, the improvement of the office-field communications, including a sense of ownership and achievement for each goal to achieve and record to break, to the point that every colleague involved in a specific operation, independently of their organization (Operator, Contractor or Service Company) is equally committed and engaged.

This Extended Reach Drilling (ERD) field re-development predominantly from four artificial islands of a giant offshore field in the United Arab Emirates (UAE) requires in most cases extremely long laterals in order to reach the defined reservoir targets, by the field development team. The giant offshore field can be effectively split in to two (2) geographical sections; East and West. The East portion of the field has been developed extensively and is considered to have good reservoir properties. The West portion of the field has much lower quality reservoir properties and requires an engineered lower completion liner in order to deliver the required well performance that will adequately produce and sweep the reservoir. The engineered liner along with the extremely long laterals means significant time is spent switching the well from reservoir drilling fluid (RDF) non-aqueous fluid (NAF) to an aqueous completion brine. In order to reduce the amount of rig time spent on the displacement portion of the completion phase, technologies have been developed to provide a method of switching the well from RDF NAF drilling fluid to an aqueous completion brine, without the associated rig time of the current displacement method. This technique eliminates the use of a dedicated inner displacement string and allows for the displacement to be performed with the liner running string, saving on average five (5) days per well. In this paper the authors will demonstrate the technology and system developed to perform this operation, as well as the qualification, testing, field installations and lessons learned that were required to take this solution from concept to successful performance improvement initiative.