The success of a fracturing treatment and long-term productivity highly depend on the residual proppant pack conductivity over time. One of the challenges operators face is the conductivity loss due to proppant flowback or sand production during production operations. As proppant particles come out of the fracture along with the production, the fracture conductivity diminishes with time as the fracture width decreases. This choking effect causes well production decline while the high-velocity low-concentration proppant particles wreak havoc on both downhole and surface equipment. As a result, proppant flowback costs millions of dollars through loss of production and expensive equipment damage. Wells experiencing these problems require remediation ranging from routine wellbore cleanouts to expensive artificial lift equipment repairs. Hydraulic fracturing became the mandatory stimulation technique to economically produce hydrocarbons in mature fields. However, proppant flowback following the fracturing treatment has been a major concern because of its detrimental effect on production equipment, leading to plugging or erosion of surface and downhole completions. The net impact of proppant flowback can be reduced production, damaged equipment, and downtime. This has prompted a detailed integrated study including both laboratory testing and development of the necessary numerical simulation models to fully understand the post-fracturing proppant flowback mechanism. Resin-coated proppant (RCP) was originally developed for post-fracturing treatment proppant flowback control. However, RCP requires a specific temperature trigger to get activated, which puts some restriction on the RCP application range. In addition, RCP requires prolonged shut-in time, which may cause issues with well cleanout, and RCP is relatively expensive. Another innovative solution that can be used for flowback control in certain conditions is a new flowback technology with nondegradable fiber proppant, designed specifically for low-temperature applications. This technology provides extraordinary proppant-pack integrity by interlocking proppant grains in a flexible 3D network. The grains do not require temperature activation and so perform equally well at any temperature below 200°F, both in oil and gas reservoirs. The fibers can be applied with any proppant (sand or ceramic), and they keep the proppant consolidated even at stress cycling conditions. Unlike RCP or other chemical treatment method, the nondegradable fibers rely on mechanical interference of the particles and not on chemical bonding. The key advantages of this technology are that consolidation is not dependent on activation temperature or time, and the proppant does not interfere with fracturing fluids or additives such as breakers that are known to be adversely affected by the presence of resin material. This paper presents the results of extensive laboratory evaluation and numerical simulation models of fiber performance, as well as global field case histories of successful application of the fiber as a solution for proppant flowback control in low-temperature environments. In all wells, remedial work has significantly dropped due to the excellent proppant flowback control. Meanwhile, the proppant flowback issues have been completely stopped, which led to remarkable success.

The Ostracod formation in the Awali brownfield is an extremely challenging layer to develop because the tight carbonate rock is interbedded with shaly streaks and because of the presence of a nearby water-bearing zone. Although the Ostracod formation has been in development since 1960, oil recovery has not yet reached 5% because past stimulation attempts experienced rapid production decline. The current project incorporated aggressive fracture design coupled with a unique height growth control (HGC) workflow, improving the development of Ostracod reserves. The HGC technology is a combination of an engineering workflow supported by geomechanical modeling and an advanced simulator of in-situ kinetics and materials transport to model the placement of a customized, impermeable mixture of particles that will restrict fracture growth. The optimized treatment design included injections of the HGC mixture prior to the main fracturing treatment. This injection was done with a nonviscous fluid to improve settling to create an artificial barrier. After the success of a trial campaign in vertical wells, the technique was adjusted for the horizontal wellbores. The high clay content within the Ostracod layers creates a significant challenge for successful stimulation. The high clay content prevents successful acid fracturing and leads to severe embedment with conventional proppant fracturing designs. We introduced a new approach to stimulate this formation with an aggressive tip-screenout design incorporating a large volume of 12/20-mesh proppant to obtain greater fracture width and conductivity, resulting in a significant and sustained oil production gain. The carefully designed HGC technique was efficient in avoiding fracture breakthrough into the nearby water zone, enabling treatments of up to 450,000 lbm to be successfully contained above a 20-ft-thick shaly barrier with small horizontal stress contrast. Independent measurements proved that the fracture height was successfully contained. This trial campaign in vertical wells proved that the combination of aggressive, large fracture designs with the HGC method could help unlock the Ostracod’s potential. Three horizontal wells were drilled and simulated, each with four stages of adjusted HGC technique to verify if this aggressive method was applicable to challenging sand admittance in case of transverse fractures. This rare implementation of HGC mixtures in horizontal wells showed operational success and proof of fracture containment based on pressure signatures and production monitoring. The applied HGC technique was modified with additional injections and improved by advanced modeling that only recently became available. These contributed to a significant increase of treatment volume, making the jobs placed in the Ostracod some of the world’s largest utilizing HGC techniques. The experience gained in this project can be of a paramount value to any project dealing with hydraulic fracturing near a water formation with insufficient or uncertain stress barriers.

During the past few years, Khalda Petroleum company (KPC) are looking forward to significant steps toward improving the economic performance of hydrocarbon producing wells in the low-permeability, heterogeneous reservoirs through the application of high impact technologies used in unconventional wells for drilling, perforating, zonal isolation, fracturing and flowback that unquestionably helped improve well performance in an efficient and economical manner. Recently, the well architecture was changed from vertical completion profile to horizontal multistage fracturing, to increase the reservoir contact. This paper reviews and discuss the well completion and stimulation methods being implemented in horizontal wells fracture stimulation in Western Desert of Egypt allowing for multistages to be fractured in one continuous pumping operation including plug-n-perforation, cemented sliding sleeves with degradable isolation drop balls and Coiled tubing deployed abrasive jetting perforating on coiled tubing with annular path pumping of the fracturing treatment and sand plug isolation. This paper provides a comprehensive evaluation and comparison of these different techniques including an overview of these completion types, detailed engineering, post-stimulation flowback/clean out, discuss the benefits and considerations, and comparison of results from the multistage stimulation methods that were applied to improve the efficiency of multistage fracturing operations. Case histories are provided to support the obtained benefits and advantages, and lessons learnt are discussed along with recommendations and what to avoid in field operations. The case history will discourse the completion strategy, operational procedures, adeptness of the isolation and time frame used. On the other hand, operational setbacks encountered during the execution of the multistage fracturing treatment will also be encompassed in the paper; to allow for future improvement; and recommendations for future field operations to achieve faster fracturing and quicker production.

Hydraulic fracturing is frequently used to create enhanced wellbore connectivity to enable tight reservoirs to produce hydrocarbon. Many factors can be considered as risks to the success of fracturing operations. One of the risks arises in reservoirs that are close to a water-bearing zone. The risk of fracture growth into the water zone limits the stimulation options and eliminates the chances of using hydraulic fracturing treatment to improve well productivity, thereby restricting the well's future production and often resulting in lost recoverable reserves. In the Western Desert of Egypt, two wells were to be fracture stimulated with a risk of propagating into a nearby water zone. The productive pay of low-permeability reservoirs is separated from underlying water zones by a weak or no stress barrier. The proximity of the water zone to the hydrocarbon-producing zone varied from 20 to 40 ft, and containing the fracture height in such well conditions to prevent the fracture propagating into the underlying water zone becomes a serious challenge. This can jeopardize the post treatment well productivity. It therefore becomes necessary to prevent fracture height propagation from growing into the adjacent water zone. This case study presents a novel hydraulic fracturing technique, applied for the first time in Egypt's Western Desert that controls fracture height growth in the absence of in-situ stress contrasts. This technique places an artificial proppant barrier below the pay zone, close to the water-oil contact, creating high resistance to fluid movement and restricting pressure transmission, thus arresting unbridled vertical height growth of fractures. These barriers are created prior to themain fracture treatment by pumping heavy proppant slurry at fracturing rates carried in a fracturing fluid loaded with high breaker concentrations. The high breaker concentration breaks the gel fast, thus allowing the proppant to settle quickly to the bottom of the created fracture. The results from the application of this newly applied dual fracturing treatment technique have been overwhelming, with a 12-fold increase in production with no increase in water production. The application of this technique resulted in an increase in the net pressure at the end of main fracturing treatment indicating fracture containment within the zones of interest. The minifracture analysis, stress profile calculation, fracture geometry characterization, and no water breakthrough after the treatment support the fracturing design.

Most of Egypt's Western Desert reservoirs are characterized to have low permeability and heterogeneous, poor rock quality. In the early development stages only layers with high permeability were produced, while the low-permeability, low-porosity layers were not considered economic. As these high-permeability layers became more mature and declined in production, tight layers became the operator's alternative choice to unlock the enormous amounts of hydrocarbons still present in these rocks and achieve economical production targets from these marginal fields. Hydraulic fracturing technology enabled us to unlock the potential of these challenging layers that were previously considered uneconomical. Hydraulic fracturing is now a common practice, even pushing extremes such as deeper, high-temperature and high-pressure wells in the Western Desert. The incremental production gains from these challenging layers have encouraged operators to invest. Currently, hydraulic fracturing is routinely conducted for all new production and injection wells and is reconsidered for the old wells. Completion practices, candidate selection criteria, perforation and design strategies, and workflows were revised to address these new challenging conditions and reservoir complexities with hydraulic fracturing technology. For example, vertical completions were replaced by horizontal multistage fracturing completions to increase the reservoir contact. State-of-the-art software was used to simplify decisions on fracture initiation points across heterogeneous reservoirs. Different technologies, alternative to conventional perforating, were introduced to enhance the proppant placement, post-fracturing production, and operational efficiency. This paper provides a review of hydraulic fracturing in Egypt's Western Desert. The hydraulic fracturing technique has been used to develop mature fields and challenging formations of Egypt since the early 1990s. More than 1,000 treatments targeting low- to medium- permeability rocks were pumped in Khalda Ridge. Correlation between mechanical properties, reservoir properties, essential fracturing design, completions, and operational parameters were established over time to help other operators that intend to apply hydraulic fracturing to their assets. Case histories are also provided, demonstrating different fracturing techniques for extreme conditions. In this paper we detail the progress related to completion practices and technologies to revive the mature fields of Egypt.