Hydrajet perforating and fracturing has recently gained popularity in the oilfield industry, especially when used with coiled tubing (CT). With coiled tubing, the task of placing many cuts at multiple places becomes straightforward and no longer time consuming. However, hydrajetting equipment life has been plagued with rapid failures, resulting in the need for time-consuming and costly tripping out and in the hole for jetting tool replacement. To reduce or eliminate such tripping costs, substantial improvements of the hydrajetting tools are required. A mere change of materials or a redesign using concepts that follow the customary models has resulted in insignificant performance improvements. It was therefore decided that a complete overhaul of the design concepts needed to be made. By doing this, substantial improvements can be obtained. This paper discusses unique improvements that have been made to the hydrajetting tools. The new tools address the aspects that have contributed to failures in the past. By taking a fresh perspective of this situation, a performance improvement of 200-300% can be attained. Recent perforating and stimulation experiences in the field demonstrate this and are discussed. Introduction Hydrajetting technology has been in use in various industries since the early 1960s (Summers 1995). From cleaning applications, such as vehicle cleaning or pipeline deposits removal to cutting applications such as cutting steel plate in fabrication or cutting rock slabs in quarries, the hydrajet tool has progressed from a simple tool for removing debris to a tool with tremendous power and accuracy. The tool has advanced from a simple tool with holes to a tool with carbide inserts or even eductors for injecting abrasives into its high-pressure fluid streams. In the oil industry, hydrajetting has been prevalent in scale removal, offshore wellhead removal, and decommissioning of offshore rig platforms. The use of hydrajet equipment also has been very successful in removing burning wellheads in war-torn areas of the Middle East. Success has also been demonstrated in perforating for well production and stimulation (Surjaatmadja, Abass, and Brumley 1994; Surjaatmadja 1993), and lately, for the stimulating process itself (Surjaatmadja et al. 2003; Rodriguez et al. 2005; McDaniel et al. 2004; Surjaatmadja et al. 2005; McDaniel et al. 2006; Surjaatmadja 2007). Because hydrajet cutting employs the use of abrasives, its life is generally limited. In surface or near-surface applications, this factor has been an acceptable risk because regular jet replacements are simple and generally not costly. In deep wellbores however, the primary expense of replacement lies in the cost of tripping, which is time-consuming and therefore expensive. Excessive tripping in and out of the hole to perform tasks is less desirable, yet often acceptable in the oil field today. However, the increased use of hydrajetting in a competitive market for stimulating and perforating, combined with increasing rig costs, has created a situation in which finding ways to reduce costs has become essential. Improving the strength of the jets has demonstrated excellent results, but efforts to continually improve the tools using conventional means may have reached a plateau (high but nowhere else to go). A totally new, patent pending concept is therefore being introduced to both improve the performance and life of jetting equipment in the oil industry.

The increased demand for natural gas from shale plays in the US has forced the industry to be more efficient and develop innovative methods for fracture-stimulation optimization. Pinpoint-fracturing methods represent a divergence from the conventional methods with minimal optimization needed to help maximize reservoir volume. Multiple-interval completions can be performed efficiently so that all intervals receive the designed proppant volumes, one interval at a time. To accomplish this efficiency, coiled tubing (CT) is used to hydrajet perforate intervals for individual fracturing treatments at predesigned depths. Using various methods, CT depths can be corrected to actual depths, resulting in the precise placement of the perforations. Proppant plugs are used not only for isolating previously stimulated intervals, but also for maximizing the near- wellbore (NWB) conductivity necessary for long-term production performance. These fracturing methods do not require removing the CT from the well between treatments, and contingencies for early screenout can be remediated immediately with minimal impact to overall completion costs. Treating intervals individually substantially reduces the amount of hydraulic horsepower required onsite. The latest pinpoint-fracturing technique provides maximum engineering flexibility in the executionof these treatments by allowing downhole control of the proppant schedule; this can be used to optimize the stimulated reservoir volume (SRV) on- the-fly, in real-time, and with downhole control. The process also incorporates large-OD CT. A recent 25-interval completion in the Eagle Ford shale demonstrated the process and is discussed in this paper.

The number of long, extended-reach wells being drilled in the oil and gas industry continues to increase. These wells present complex challenges in completion and intervention procedures because operators demand the same level of performance achieved on shallower wells while providing a cost-effective and safe solution.To reach deep target depths with coiled tubing (CT), smaller coil must be used because of reel capacity, which limits pumping rates because of pressure and velocity limitations. Many areas have road weight restrictions that will also dictate the size and length of CT that can be used. As an alternative, jointed pipe can be used; however, using jointed pipe reduces the overall efficiency of the process, as continuous pumping cannot be achieved.The new hybrid system uses both CT and jointed pipe in a single workstring. The system incorporates a unique flapper safety valve that enables seamless functioning of the string in a live well. The hybrid system enables larger CT and jointed pipe to be deployed, which results in higher pumping rates and depths. This reduces the overall job time, while improving safety and efficiency for deeper well applications, including multizone stimulation, cleanouts, drilling, and mill-outs. This paper presents the hybrid system design and benefits in multizone stimulation, drillouts, cleanouts, and other wellintervention applications. Also included is a case history to demonstrate the success of the system when applied in a multizone fracture-stimulation treatment. IntroductionCT is a vital tool for oil and gas operators to achieve safe, efficient, and effective well-intervention operations. Typically ranging beyond 25,000 ft in length and from 1 to 2.875 in. in outside diameter (OD), these continuous strings of pipe are uncoiled into live wells to perform milling, drilling, cementing, logging, perforating, fracturing, completion, or maintenance operations. Deeper well completions with extended-reach horizontal laterals have presented some unique problems to those seeking to perform well-intervention operations.

Worldwide demand for energy has forced the energy services industry to increase process efficiency and create innovative new methods of fracture stimulation optimization. Pinpoint fracturing methods represent a divergence from conventional fracture stimulation methods, which provide minimal optimization to reservoir volume. Pinpoint fracturing methods allow multiple interval completions to be performed efficiently, helping ensure that all intervals receive the optimum fracture intensity. To increase process efficiency, coiled tubing (CT) is used to hydra-jet perforate intervals for individual fracturing treatments at predetermined depths. The process uses a unique bottomhole assembly (BHA), which was recently redesigned to increase the efficiency of the hydra-jetting tool and isolate the fracture stimulation from previous intervals. This pinpoint fracturing method does not require removing the CT from the well between treatments. Risks of non-productive time (NPT) are mitigated because contingencies for early screenout avoidance can be initiated immediately during the fracture stimulation with minimal impact on overall completion costs. Treating intervals individually substantially helps reduce the amount of hydraulic horsepower required onsite, further reducing completion costs and the risk of NPT caused by down horsepower. Re-innovating fracture stimulation technology is often a challenge. The new technology must add value and efficiency to the process, while remaining reliable and commercially viable. In this case, these requirements were met by reducing the complexity of the BHA while increasing hydra-jetting efficiency. The elimination of moving parts increased the process reliability and simplified operational procedures. This paper examines the re-innovation of this older technology.

Wells in the oil-and-gas industry continue to be drilled to deeper depths. These wells present complex challenges for completion and intervention operations because operators demand the same level of performance achieved on shallower wells while providing a cost-effective and safe solution. The size of coiled tubing (CT) deployed in deep-reach wells is maximized to achieve a greater level of performance and operational efficiency, while reducing the pressure requirements of equipment. However, weight restrictions, reel capacity, depth, and trajectory of the well can limit the size of CT that can be used. Using a new cationic polymer friction reducer allowed CT operations to achieve higher rates and velocities while maintaining hydrostatic pressure and lowering surface-treating pressures. The friction reducer has the following attributes: It is salt tolerant, which enables a wider scope of use.Effective at low concentrations.Easily mixed on-the-fly.Compatible with nonionic additives.Can be used up to 200°F.Compatible with shale formations.Extremely rapid hydration.Created for use with water-based fracturing fluids in unconventional shale formations.Gives the customer the ability to reuse flowback and produced water without damage to the formation or addition of fresh water. This paper describes the new friction reducer and the benefits of using it in unconventional shale formations. Also included is a case history to demonstrate the success of the system in CT drillouts. These field trials provided data to confirm the following benefits. A 25% treating-pressure reduction was achieved; 20% was predicted using an existing friction reducer.Using a friction reducer lowers pumping pressure and hydraulic-horsepower requirements.The system enables increased pumping rates, lowered surface-treating pressure, and higher velocities.Cost savings were achieved and and value was added to the operator.