In the western desert region of Egypt, previous propped multiple-fracture treatments were performed using conventional methods (i.e., perforate, frac, set mechanical/zone isolation, and repeat cycle). Although the resulting treatment efficiency was satisfactory, other methods were being considered to help reduce cost and improve production performance. Also, it was desired to decrease total operational time, which would further impact economics (rig time, production delay, etc).In an attempt to improve production response, fracturing designs in the El Fadl field in the western desert went from a standard three-stage design up to as much as a six-stage design to more effectively stimulate the pay zones. A careful review of the field and operations suggested possible benefits from implementing the pinpoint method for hydraulic-fracturing treatments. It was, however, not a simple case of just applying a hydraulic-fracturing treatment to every potential zone, but required proper well screening, thorough log analysis, calculating and validating mechanical rock properties, and enhanced 3D fracture modeling to achieve a successful campaign.A pinpoint method for stimulation was implemented to perform multistage jobs at reduced costs. As the stage count per well was increased, production response and economics were improved. Both treatment design and staging design with this fracturing technique continue to be further refined as performance and statistical analysis of previous design changes are completed.This paper discusses a pinpoint method for frac treatment and the methodology applied on a recent well. Differences in job execution that will be discussed include: using a hydrajet perforating mechanism instead of conventional casing-gun perforation, time-consumption reduction, analysis of vertical-fracture coverage per potential zone, and cumulative production response from the different designs tested. This could serve as guidelines for other operators who might be facing similar challenges in the North Africa region and elsewhere.

Miqrat is a complex clastic deep tight gas reservoir in the North of the Sultanate of Oman. The Lower unit of the Miqrat formation is feldspatic sand characterized by low permeability not exceeding 0.1 mD and porosity up to 12 %. Based on results of the appraisal campaign of Field X, it contains significant volume of gas. However the production test data after fraccing showed mixed results. The objective of this study to explain the production behavior in relation to the frac geometry. Understanding the reason of possible overestimation of log derived Hydrocarbon saturation is important. Thus the interpretation of conventional and special logs was revisited. In parallel, all the available core data including SCAL and thin sections were dissected. Besides, the analysis of hydraulic fracture propagation, well tests, cement quality, PLT including Spectral Noise Log was performed. The wells were subdivided into categories according to their production. –wells producing no water–wells with water channeling from the water leg of Middle Miqrat–wells with transition zone intervals with two-phase inflow of water and gas. There are three main challenges that needed to be overcome. First challenge is to identify the high uncertainty in hydrocarbon saturation from the resistivity logs. Petrophysical evaluation shows that porosity profile derived from logs looks very similar in all wells with insignificant lateral variations. Hydrocarbon saturation estimated from logs looks also similar regardless of how deep or shallow the well is. However, production tests show different results, e.g. different flow rates and high water-cut are observed in some wells. The second challenge to keep the frac height below the boundary between Lower Miqrat and Middle Miqrat, which consist of around 3 to 7 meters of shale and in most of the field it is bound with water. The third one is to cover the upper part of the zone below the shale since it is the best part of Lower Miqrat without breaking to the water leg of Middle Miqrat. A geomechanical model was created and several frac model iterations were run since in the early appraisal well that boundary was broken. Investigation through multidisciplinary integrated team led to unlock the tight gas reserves in Lower Miqrat. Based on open hole log interpretation to create a geomechanical model. That model is being calibrated with DFIT, 3 different case hole logs and confirmed with production.

In the last decade, hydrocarbon production from low-permeability reservoirs has been on the rise. Multi-stage hydraulic fracturing is the most common technology used to make production from such reservoirs economically viable. Radioactive-tracers and production logging, which are usually used to assess fracture flow efficiency, do not always provide reliable information in terms of the fracture effectiveness and total frac flow height. An advanced technique described in this paper not only can identify active fractured intervals but also quantify the inflow profile. A novel technique was developed to locate fracture inflows and quantify inflow profiles in hydraulically fractured wells. It builds on the industry-proven combination of Spectral Noise Logging and High Precision Temperature Logging. This technology was initially implemented for qualitative and quantitative analysis of reservoir flows, including those through leak points, cement, reservoir rock matrix and reservoir fractures. Fracture flow intervals are located using a new-generation of Spectral Noise Logging tool with wider dynamic and frequency ranges. Quantitative inflow profiles are derived by temperature modelling. The technology described in this paper allowed assessment of hydraulic fracturing effectiveness in the producing wells of Petroleum Development Oman. Three case studies are presented to demonstrate the application of this technology in two producing gas-condensate wells and one oil well, one vertical gas producer and the other horizontal, drilled into clastic low-permeability heterogeneous layer-cake reservoirs and therefore requiring multistage hydrofracturing for commercial hydrocarbon production. Production profiles were determined for all wells, with inflow splits between producing zones quantitatively analysed using temperature modelling, matching the recorded and modelled temperatures, pressures and phase compositions, and taking into account surface data, such as production history and separator test data, and PVT fluid properties. Spectral Noise Logging was used to determine the frac flow intervals. In the vertical well, the survey was conducted at three different flow rates to improve inflow quantification by matching three data sets. The survey results were used to successfully evaluate the effectiveness of multi-stage hydraulic fracturing and fracture height. The acquired information was used to improve hydraulic fracturing planning and design for the field. One of the advantages of applying this technique for fracture flow evaluation is its ability to survey wells under existing operating conditions without shut-in and production deferment. As opposed to conventional production log with spinner, described technique can locate and quantify flow behind pipe.

The global horizontal well fracturing market has grown tremendously in the last decade with the increase of multistage fracturing operations. Many of these wells are cased and cemented and had a sequence of a plug and a series of perforations for each stage of the fracturing process. Intervention optimization became a key element for work efficiency and thus cost reduction. A common approach worldwide is to pump-down the plug combined with a few guns and initiate the firing downhole sequentially using switches. Despite the efficiency of this technique, it requires an overflush after each fracturing stage to clean the wellbore of leftover proppant and allow free passage of the plug and guns to be pumped down. Unfortunately, overflushing hampers the fracture's performance because it allows the fracture to close near the perforations. This effect on productivity is now being realized on these overflushed wells, although these wells were once constructed very efficiently. To move away from overflushing, some operators switched from pump-down to coiled tubing (CT) conveyance of the multiple guns. Conventional CT or CT with electric wireline were used, and each technique has its own advantages and limitations. A newer technology is CT equipped with fiber optics in combination with an optic-based selective perforating system that enables the firing of multiple guns in a single run. This technology combines the advantages of both the conventional CT and the CT equipped with wireline cable. Equipped with gauges, the CT equipped with fiber optics also permits better acquisition of fracture data in horizontal wells. The result is a more efficient operation, better fracture evaluation, and well productivity enhancement by avoiding the damaging effect of overflushing. After an evaluation of current conveyance techniques, an implementation trial of the new technology on multiple fracturing stages was performed in a horizontal well in Oman. The first trial showed successful application of the technique, especially the accurate real-time gamma ray and casing collar locator (GR-CCL) correlation of the multiple short guns. Even more important was the successful placement of the proppant into the formation during the hydraulic fracturing process. The technique was shown to be efficient while mitigating the possible damage to the formation.

In low-permeability formations such as tight gas reservoirs, a well would be economic only if an effective hydraulic fracturing technique is selected. In central part of Sultanate of Oman a deep tight gas field is developed with hydraulic fracture stimulation. Normally, between 7 and 13 frac stages are done per well. Majority of wells are vertical with pay zones separated with shale layers that prevent fracture growth. Plug & perf is a common technique used in this field, therefore there are multiple well interventions during Hydraulic Fracture operations that consume time and delay the well delivery. By deploying multistage frac completion with the objective of producing, enhancing and cost/time savings, the effectiveness of the fracturing operations was expected to increase. Equipment selection, design and development was performed based on well conditions, casing design, operational parameters and production gas composition. Multistage frac completion allows the frac operation to be continuously performed without the need to conduct intervention activities such as running/setting frac plugs, perforating, milling and clean-out between intervals. The intervention activities can be conducted at the end of the frac operation in single-trip deployment if desired. The success in North America in horizontal tight gas wells has opened a door for implementation of this system in vertical wells in Sultanate of Oman. The main challenge in deployment of this system in vertical wells is the accurate positioning of the sleeves. The shale layers between the pay zones could be as narrow as 5 m or less and a small pay zone might be easily missed. Besides, deployment and cementing operations are equally essential as proper zonal isolation is a must with water zones embedded in between. This paper is discussing the lessons learned from utilization of multistage frac completion in vertical deep wells (around 5000 m) covering the completion and Hydraulic fracturing stimulation operations. This technique has proven significant cost & time reduction and production increase as well as reduced HSE exposure contributing to better gas recovery, improvement in operator's performance and energy delivery to the country.