Hydraulic fracturing effectiveness depends on the cost and properties of the selected propping agent. The methods and fluids that create fracture width and transport the proppant along the fracture width also have a significant impact. Recent advancements related to channel fracturing design, execution, and evaluation addressing all these components have enabled proper modeling and further treatment optimization. This work provides a detailed overview of several years of laboratory experiments, research, modeling, and global field testing of enhanced channel fracturing methods. Channel fracturing is well known for breaking the link between fracture conductivity and proppant permeability by replacing a continuous proppant pack with open channels inside the fracture using intermittent proppant feeding. To prevent proppant settling during fracture closure, degradable fibers have been effectively utilized within the fracturing fluid for over 10 years. This technique achieves maximum fracture conductivity while minimizing proppant cost. Decoupling proppant performance and fracture conductivity enables replacing ceramics by natural sand, thereby significantly improving field development economics in many areas of the world. Furthermore, extensive laboratory research has qualified new fibers for application of channel fracturing across a wider reservoir temperature range. Research and laboratory experiments were conducted to construct a workflow to model and optimize sand transport and the resulting channel geometry. Fiber and proppant transport modeling results compare extremely well with experimental results and provide excellent resolution and accuracy. This work also demonstrates that intermittent pulses of proppant with fiber effectively creates reliable channels in the fracture. Also, improved software and equipment enhancements allowed accurate fiber and proppant synchronization, making the placement of fiber-free channels possible. Recently developed advanced modeling tools have improved understanding of channel formation in the fracture, thereby enabling treatment design optimization. The enhanced models further enable evaluation of different materials selection, for instance, replacing ceramic proppant with natural sand in the channeled area of the fracture. A comprehensive case study of channel fracturing implementation in Saudi Arabia proved the method to be effective for improving proppant placement and fracture geometry to yield improved incremental production. Another field case in the region demonstrated the ability to replace ceramic proppant with natural sand without sacrificing any channel conductivity. The study breaks new ground in the stimulation of extreme low temperature and high temperature formations by extending the channel fracturing technique, enabled by the introduction of a new solids transport concept and the development of new fiber compositions. When combined with accurate modeling, improved economic results were achieved by using locally produced sands to replace ceramic proppant while consistently delivering highly conductive fractures. The project includes laboratory testing, a detailed simulation model description, and field examples.

Technology Focus As gas development focuses more on tight and ultratight formations, the challenges to produce economically become diverse and more intense. One main challenge faced while fracturing a well is a high fracture gradient. This can be caused by near-wellbore tortuosity, drill-in-fluid-induced damage, high build-up of filter cake, or far-field tectonics and stresses. Formations with high fracture gradients result in high breakdown pressure and frequently need very high treating pressure to fracture the interval effectively. This may cause problems with completions integrity, and, depending on the intensity of treatments and pressures reached to propagate fractures, wells may no longer be accessible because of tubular deformation. Also, if fracturing stages are skipped while treating hard rocks because of completion limitations or some stages not being treated effectively and uniformly, production will fall far below expectations. If high breakdown pressure is caused by near-wellbore damage and tortuosity, attempts can be made to lower it with chemical treatments such as mutual solvents or acids or with the help of mechanical means such as hydra-jetting, reperforation, or slotting. When it comes to far-field high-stress regimes, the in-situ stress magnitude and fault stress regime should be well-known, evaluated, and calculated to prepare for high surface pumping horsepower. Advanced completion technology that can accommodate high-pressure/ high-temperature conditions is frequently required to perform the desired stimulation treatments. Before embarking on the remedial tasks, important steps include reviewing well location and placement, selecting a well trajectory in the more-prolific interval, completing with multistage fracturing assembly in better rocks, using nondamaging fluids for fracturing, and using optimal treatments with appropriate additives that will ensure high fracture conductivity. Parts of the fracture stages that do not contribute to production because of reservoir and geomechanical heterogeneity can be reduced by the use of an engineered approach in selecting the well location, the drilling direction and azimuth, completions placement, stage and cluster design, and fracturing techniques combining real-time monitoring and optimization. Otherwise, identifying the reason for low producers becomes difficult, whether they are the result of bad completions and poor fracturing design or reservoir development and quality. The use of appropriate fracturing fluid is also important to lessen high breakdown pressures, induce sufficient length and width to carry proppant in proppant fracture treatments, and reduce or eliminate formation damage and forming of scales. Scales formed because of fluid incompatibility can deteriorate fracture and formation conductivity dramatically and obstruct gas flow. The use of seawater as a base fracturing fluid is gaining momentum in the Middle East because it is a viable alternative to fresh water, thereby reducing stimulation cost. Seawater needs treatment such that precipitation while interacting with formation water does not become severe and impair production. Treatments such as phosphonate-based inhibitors are tested and considered to address the effect of hypersalinity and precipitation of barium, calcium, and strontium sulfate that reduce gas flow. Phosphonate-based scale inhibitors are introduced for high-temperature treatments. SPE 189896 Fracturing in a Tectonically Stressed Area Under Anomalously High Gradients by Dmitriy Abdrazakov, Schlumberger, et al. SPE 186313 First Application of Residue-Free Fluid System for High-Temperature Fracturing Treatment in Saudi Arabian Carbonate Formations by Zillur Rahim, Saudi Aramco, et al. SPE 186212 A Comparative Work Flow for Different Hydraulic-Fracturing Techniques in the Western Desert Oil Fields of Egypt by Ahmed Abd ElHamid, Qarun Petroleum Company, et al.

Abstract Heterogeneus deep carbonate reservoirs require enhanced development strategies to maximize reservoir contact and ultimately to increase the recovery factor. In some complex carbonate reservoirs, conventional strategies for reservoir development are not always the best choice and new technologies have to be applied to optimize the reservoir development. In such cases, underbalanced coiled tubing drilling (UBCTD) has proven to be a suitable approach to exploit more complex reservoir areas, where conventional drilling and stimulation techniques no always meet well productivity expectations. The UBCTD technology consists of drilling a well with a drilling fluid pressure lower than the reservoir pressure, which tends to minimize the formation damage. Due to the underbalanced condition imposed in the wellbore, the well is allowed to flow naturally during drilling, while its productivity is measured. Another technique that accompanies this strategy is called bio-steering, in which cuttings are inspected while drilling to detect micro-fossils from the reservoir. Based on the real-time well productivity and the micro-fossils appearance, the well trajectory can be adjusted and corrected during drilling to chase the good wellbore productivity layers. A number of wells has been drilled using this strategy with encouraging results so far, which opens a great window to continue exploiting the reservoirs under development. With this technology, multilateral placement is possible with a high degree of accuracy across thin reservoir layers, which maximize the reservoir contact and increases the well productivity. This work presents a general description of this technology as well as present a successful field case including all stages from well planning to well execution and testing.

Ordinary acid fracturing treatments cannot deliver consistent production results in low-pressure carbonate reservoirs. The reservoir pressure is not sufficient to flow back the large volume of treating fluids from the formation after the treatment, thus minimizing the benefits of performed acid fracturing. The use of foamed acid fracturing fluids will provide additional energy that will help to enhance flowback and push treating fluids out from the reservoir during post-fracturing flowback operation. There are two types of gaseous phase that are commonly used to foam the fluids for stimulation treatments: nitrogen (N2) and carbon dioxide (CO2). N2 is an inert gas; it is widely available and therefore the most frequently used. CO2 is more soluble in water than N2; therefore, more CO2 is required to saturate the liquid and create the foam. CO2 has more expansion during flowback, which aids in total fluid recovery. Additionally, the solubilized portion of CO2 reduces the interfacial tension of the fracturing fluid. A deep high-temperature carbonate reservoir typically requires acid fracturing treatment to produce at economic gas rates. When reservoir pressure declines over time, foamed acid fracturing treatment becomes the preferred stimulation option. Both types of the gaseous phase show good success. The multiple case studies suggest that foamed acid fracturing resulted in easier flowback initiation and better well productivity compared to regular acid fracturing. Moreover, CO2-based foams provided better results compared to N2 foams, especially in horizontal wells completed with multiple acid fracturing stages within the same reservoir. The specific fracturing fluid was deployed to use CO2 foam in the wells with high bottomhole temperatures up to 300°F. The innovative CO2 foam chemistry enables formulating non-crosslinked gels that deliver viscosity equal to or better than the industry-standard foams of low-pH guar crosslinked fracturing fluids. This fluid delivers those results at significantly lower polymer loadings and with a reduced number of additives, thus improving the operational aspect and increasing well productivity. Another noticed benefit of foamed acid fracturing with CO2 is the easier achievement of higher foam quality at bottomhole conditions. N2 is pumped in its gaseous phase and requires specific pumping units with limited pressure and rate capacity. In contrast, CO2 is pumped in its liquid phase through the common fracturing pumping units; therefore, a significantly higher pumping rate of the gaseous phase can be achieved with minimum additional equipment.

Technology Focus Oil and gas reservoirs of low porosity and permeability will usually require drilling horizontal wells and conducting optimal hydraulic-fracturing treatments to attain commercial productivity. High production rates and long-term production sustainability are achieved by optimizing well placement (from setting well landing points and overall trajectory plans to reaching total depth), customizing completions design to fit reservoir and production conditions, and improving hydraulic fracturing to boost reservoir contact and flow capacity. Reservoirs of moderate to relatively higher permeability might also require high-rate matrix acidizing to clean up the near-wellbore region and connect the well to the reservoir. Significant improvements to completions design and manufacturing have been made recently to accommodate long laterals and multiple fracturing or acidizing stages for different reservoir types, lithologies, and conditions. One such openhole completion is the controlled-injection and even-distribution ball-actuated limited-entry system where a long portion of the reservoir can be effectively isolated in one interval with hydraulically set mechanical packers. Multiple sleeves placed at intervals facing zones of interest are activated for stimulation with a single ball dropped from the surface. These multiple sleeves can be separated further by zonal-isolation packers to enhance stimulation efficacy through each sleeve. One major challenge of multistage systems is to ensure that all stages are stimulated effectively. Surface pressure readings while pumping the job are necessary but not sufficient by themselves because they cannot always capture the subtle intricacy of fracturing-port openings because of many other pressure-change-related events occurring simultaneously. Newly initiated high-resolution acoustic-related measurements have been introduced and used that are compatible in openhole and cemented applications, effectively capturing sleeve opening and closing even in the absence of a pressure signature. A set of sensors placed on the wellhead measures acoustic events in real time. At the stimulation-fluids front, a new single-phase retarded-acid system for high-temperature reservoirs has been developed and used for deeper penetration of live acid. The system has a low friction pressure, enabling higher pump rates, and does not require diesel as is needed for emulsified acid. The acid system is also used with engineered diversion mechanisms that are biodegradable and available in variable sizes, where the bigger blends are intercepted at the entrance of the fracture while small particles reduce permeability to create temporary isolation. The purpose of the diverters is to distribute fluids into several open intervals in a uniform fashion to create even stimulation treatment and simultaneously improve acid penetration. The diverters are held together with fibers that ensure the integrity of the blend during pumping and enhance the bridging effect. Energized fracturing fluids with liquid carbon dioxide in different foam qualities also are proving successful in low-pressure, partially depleted areas, enhancing flowback and cleanup of the well and saving water. Many new technologies are evolving, upcoming, being tested, and being implemented in the completions-and-hydraulic-fracturing sector. Recommended additional reading at OnePetro: www.onepetro.org. SPE 178963 Effect of Microproppant on Production in the SCOOP Woodford Shale: A Case History by James Calvin, Halliburton, et al. SPE 183725 Optimizing Well Potential—Technologies That Affect Hydraulic-Fracturing Efficiency by Zillur Rahim, Saudi Aramco, et al. SPE 187451 Proppants—What 30 Years of Study Has Taught Us by R.J. Duenckel, Stim-Lab, et al.

Abstract With the increase in gas demand and the need to supply additional energy, the focus is now shifted to drilling and production activities exploiting high-pressure/high-temperature (HPHT) tight sandstone gas formations. The design optimization and selection of proper hydraulic fracturing technology is a key to succeeding in getting an economic gas production rate. Using well performance as the primary determining factor, a systematic study and evaluation was conducted on 20 vertical and horizontal wells drilled in HPHT heterogeneous sandstone reservoirs to assess effectiveness of stimulation treatments and benefits of using novel technologies. The numerous variables analyzed to determine the impact on production include different completion options, type of fracturing technology used, various proppant and fluids, fracturing method, production rate, and flowback parameters. A comprehensive database for stimulated wells was created that included reservoir parameters, completion data, minifrac and main stimulation treatment parameters (additives, fluid and proppant types, volumes, rates, and pressures), post-fracturing flowback results, and monthly production data. The production data were normalized on reservoir quality to strengthen the effect of fracturing parameters on well productivity independent of reservoir quality. Correlations were drawn using the Pearson correlation coefficient to compute the upward and downward data trends, ensure use of good quality data, and discard the few nonaligned data. Numerous very useful plots were constructed that show the different trends of the variables evaluated and how they affect production rate. The results demonstrate the importance of proper well landing with strong influence of reservoir quality on postfracturing production results. The channel fracturing technique offers near-infinite fracture conductivity and shows very promising results compared with conventional treatments. Pumping the bigger fracturing jobs typically yields better production results, but proppant type and schedule should be designed accounting for reservoir quality. Pad volume should be designed to achieve optimum pressure at the end of the treatment, not too high but not too low. Post-fracturing production parameters are as important for the well performance as the stimulation treatment itself. The analyses identified the key post-fracturing production drivers in the gas reservoirs and ways to improve production of future wells drilled in various formations under similar conditions.

Abstract To economically produce gas from tight reservoirs poses challenges resulting from high bottomhole temperature, low permeability, and high Young’s modulus and rock compressive strength. Hydraulic fracturing, which is necessary to exploit the tight reservoirs, faces constraints such as high fracture initiation and treating pressures, risk of premature screenout, and conductivity degradation. A conventional fracturing treatment in such challenging environment necessitates increased polymer concentration in fracturing fluids and using smaller-size proppant at low concentrations. This results in shorter effective fracture half-length and low fracture conductivity. Additionally, high polymer concentration is not easily cleaned up and may create further damage to the proppant pack. These challenges are compounded where the reservoir is relatively tight and often cannot supply enough energy to clean up the injected fracturing fluids. To overcome these challenges, channel fracturing was introduced in which proppants are added in pulses to the fracturing fluids, creating stacks of pillar-like structures inside the fracture. These pillars hold the fracture open, and the voids surrounding them form stable channels along the entire geometry of the fracture thereby providing an open pathway with near-infinite conductivity. The technology reduces amount of proppant pumped compared to a conventional treatment, and most of the standard expensive high-strength proppant, required for fracturing in high-stress environment, can be substituted by intermediateand low-strength proppants or even natural sand. The hydrocarbons will flow through the open channels and not through the pack. Additionally, pulsation of proppant during pumping virtually eliminates the risk of a screenout. Extensive laboratory tests have been conducted to verify the concept of using nonstandard proppant with channel fracturing in high-stress formations. The results of these tests were positive, and trial treatments have been pumped. To date, more than 50 channel fracturing treatments have been conducted in the clastic reservoirs. Some of them have been performed with nonstandard proppant as a part of the treatment. No screenouts were observed even in the formations that were tight with narrow pressure margin between the in-situ stress and completion integrity limitations. Production results after channel fracturing treatments are more consistent compared to conventional proppant fracturing and are not related to the type of propping material used.

Technology Focus Hydraulic fracturing is widely used all over the world, and in the Middle East in particular. Although superhigh-quality reservoirs do not need stimulation, the current expansion of reserves is mostly in newly found tight and unconventional resources that require extensive multi-stage fracturing for commercial production. Saudi Aramco embarked on stimulation and fracturing of wells at the beginning of its nonassociated conventional gas development endeavor and has been expanding and improving continuously in the areas of fracture design, use of novel materials, and field implementation. With newly discovered fields and the extension of existing areas, the challenges related to reservoir heterogeneity, tight rock, layered systems, and field maturity have led to innovative ideas and to testing and application of technologies. The use of biodegradable novel diversion systems (NDSs) has allowed fracturing multiple intervals in a single-stage operation, thereby reducing time and significantly cutting operational cost. On the basis of petrophysics and reservoir and geomechanical characteristics, multiple mesh sizes of an NDS are carefully designed and used to divert fluids in the wellbore, ensure simultaneous treatment of lower-quality intervals, and control excessive leakoff inside the fracture, creating longer and planar fractures for improved production. Diagnostics using production logging, temperature logs, and injecting and measuring nonradioactive tracers have shown expected production contribution and increase from target intervals, in both acid- and proppant-fracturing treatments. The superiority of NDSs lies in their natural formulation, simultaneous use in near-well and far-field applications, robustness in creating barriers and diversions, and easily degradable nature and flowback. Among other technology being developed and adopted in Saudi Arabia is the use of seawater-based fracturing fluids that will save the more-valuable fresh water. The laboratory experiments and the few field applications to date have shown stability at high temperatures and pressures, compatibility with formation fluids and fracturing additives, and resilience against scale formation. The use of seawater will serve the environment tremendously and will provide substantial economic benefits in remote areas where access to fresh water is challenging and costly. Saudi Aramco also has initiated the use of local sand as proppants combined with the channel fracturing technique, where proppants serve as pillars supporting and maintaining the induced fractures, keeping them open while the actual fracture conductivity is provided by the open areas within the system. The crushing of pillars by high in-situ stress and the friable quality of sand and consequent release of fines are controlled and contained by the use of resin during the treatment. This technology is also designed to reduce fracturing cost by eliminating more-expensive intermediate-strength proppant (ISP) or high-strength proppant (HSP) during channel fracturing. Sand cannot substitute for ISP or HSP in conventional fracturing because of its low compressive strength and friable nature. The economic advantage achieved by the use of new technologies will help expansion, exploration, drilling, and fracturing in new frontiers and territories. The world’s increasing energy demand, which, for the most part, is hydrocarbon dependent, requires growth and advancement in the oil and gas industry, increasingly environmentally friendly practices, the use of more natural resources, and the application of innovative ideas and new technology that will reduce development and management cost and increase efficiency and effectiveness. Recommended additional reading at OnePetro: www.onepetro.org. SPE 180207 Effects of Hydraulic Fractures on the Treatment of Condensate by Huff ’n’ Puff Gas Injection in Eagle Ford Shale by S. Yang, University of Calgary, et al. SPE 181353 Best Practices and Lessons Learned From More Than 1,000 Treatments: Revival of Mature Fields by Hydraulic Fracturing in Khalda Ridge, Egypt’s Western Desert by Mohamed Salah, Khalda Petroleum Company, et al. SPE 184840 Innovative Diversion Technology Ensures Uniform Stimulation Treatments and Enhances Gas Production: Examples From Carbonate and Sandstone Reservoirs by Zillur Rahim, Saudi Aramco, et al.

Abstract Gas-bearing carbonate reservoirs in moderate to low permeability reservoirs have been targets for acid fracturing treatments in the Middle East. These formations typically exhibit high temperatures, medium to low porosity, and high heterogeneity in terms of lithology and reservoir properties. The heterogeneity dictates completion strategy, with multiple perforated intervals across large gross height in vertical wells with subsequent acid fracturing treatments that aim to cover all perforated intervals in a single treatment. But due to differences in lithology, intervals with high dolomite content are less likely to receive stimulation due to higher stress and reduced acid reactivity. Temperature logs performed on many wells after conventional acid fracturing treatments showed that these perforated intervals accept only a small amount of treating fluids, compared to intervals perforated in clean limestone. An efficient, non-damaging, near-wellbore diverter is required to efficient treat all intervals and improve productivity in such wells. The objective is to stimulate all existed intervals in a single pumping operation, regardless of reservoir heterogeneity, by using degradable diverting materials to temporarily isolate created fractures and redirect the flow to untreated areas. The diversion material used is a composite pill comprising a proprietary blend of degradable fibers and multimodal particles, designed to provide an effective isolation plug at the face of the reservoir in a consistent manner. Fibers are added to ensure the integrity of the diversion pills during delivery and to enhance the bridging mechanism. The use of fibers allows minimizing required diverter volume to few barrels and engineered multimodal diverting materials allow having very strong diversion pressure with small amount of the material. The process increases operational efficiency, well productivity, and estimated ultimate recovery. The materials used to provide temporary isolation have proprietary formulation that degrades within hours or days, depending on bottomhole temperature, with no need of intervention or pumping chemicals to break down the system. Two pilot treatments with degradable diverter were conducted in high temperature high pressure carbonate reservoirs. Extensive measures were undertaken to evaluate the treatments, including pressure analysis, separator tests, temperature logs, production log (PLT), pressure build up (PBU), and nodal analysis. Overall, the measurents and analysis of the treatments proved the efficiency of the degradable diverter for vertical wells: sharp pressure increase up to 1,600 psi when pills arrived at perforation; cooldown effects in all intervals on the post-fracturing temperature logs ensuring uniform distribution of the acid; high flowback gas rates, substantially higher than those of offset wells treated without the diverter; fracture response and signature observed on PBU data; PLT contribution from most of the perforated intervals confirming that treatments penetrated all intervals of interest; and nodal analysis with good production match showed long etched fracture half-length - a preferred fracture geometry for tight reservoirs.

Abstract Well stimulation and intervention are typical activities to enhance the productivity of gas-bearing sandstone reservoirs and meet the increasing demand for energy. Many wells target sandstone formations that require stimulation to produce gas at an economical rate. Proppant fracturing is the preferred stimulation method for such reservoirs because it creates highly conductive pathways between the wellbore and the reservoir. Prior to any fracturing treatment, sufficient injectivity at an acceptable bottomhole treating pressure (BHTP) needs to be established. Depending on the reservoir quality, the task of breaking down the formation and establishing a sufficient injection rate may sometimes be challenging due to the high in-situ stress and compressive strength of the reservoir rock. Formation breakdown pressure can exceed the completion limitation due to stress alteration zones around the wellbore. For such cases, interventions using coiled tubing (CT) are often required to proceed with the hydraulic fracturing operation. Two well-known remedial CT treatments are typically used to address wells with high breakdown pressures or low injection rates. The first is treatment by chemical means. Chemicals containing organic solvents or acids are squeezed into perforated intervals in the wellbore; subsequent soaking of the well with such chemicals can help remove some of the near-wellbore damage induced by drilling. The second is treatment using a mechanical approach; abrasive fluids containing gelled fluids and sand are jetted at high pressures through a nozzle at the target depth to create a cavern that connects the wellbore with virgin, non-stress-altered sections of the reservoir. More than 10 interventions performed over the past five years are analyzed in this paper. These include both abrasive jetting and chemical squeeze job techniques. Analysis indicates that only half of the abrasive jetting jobs were successful, and none of the chemical squeeze treatments provided positive results. Based on detailed analysis, ways forward were determined that will improve the success ratio for remedial actions using CT, including employing fiber-optic real-time telemetry to precisely place the bottomhole assembly and perforating with CT to optimize operational efficiency. This paper provides an analysis of the well intervention practices that aid fracturing operations and prevent challenging situations such as high breakdown pressure that result in unsuccessful fracturing treatments. The knowledge obtained from this analysis can be extended to other regions where similar breakdown challenges exist.

AbstractNovel approaches in hydraulic fracturing treatments are needed in challenging high pressure high temperature tight gas-condensate reservoirs to achieve the objectives. The implemented technologies should not only provide substantial increment in well productivity, but also needs to be economically attractive and provide superior efficiency in terms of materials, services and time required. In the recent years many technologies were implemented in Saudi Arabia that aims to improve hydraulic fracturing efficiency and this paper focuses on the case studies and lessons learned from their implementation. Sequenced fracture diverters allow to pump multiple proppant or acid fracturing treatments in a single pumping operation, saving the cost of completion and time of wellsite operation. Channel fracturing technology mitigated the risk of screenout in proppant fracturing and enabled placing fractures with nearly infinite conductivity by pumping twice less proppant. Advances in completion technologies enabled drilling horizontal wells and completing them with multistage stimulation completions where multiple hydraulic fracturing stages can be pumped without need for any well intervention operations between the stages. Implementation of swellable packers further improves this process by providing more reliable isolation between stages. Nano-filtration combined with selection of proper additives allows usage of sea-water for the fracturing operations in the desert area where consumption of fresh water needs to be minimized. Usage of foamed fluids for fracturing operations in depleted gas reservoirs helped to minimize volume of pumped water and significantly facilitate in flowback operations, often makes possible to perform them without need for costly and time consuming coil tubing operations.

Abstract Saudi Arabian nonassociated natural gas development programs are continuously expanding to meet the local energy demand. The challenges faced in the new development areas attributed to reservoir heterogeneity, high-pressure and high temperature, and low reservoir quality have been thoroughly evaluated and encountered with the application of fit-for-purpose novel technologies and the implementation of best practices. Drilling of horizontal wells and completing those with multistage fracturing (MSF) have been a preferred practice to obtain and maintain high and sustainable production and to help marginal wells become economical. One main focus area for the enhancement and improvement of stimulation efficiency is fracturing fluid additives. Regardless of the base gel and loading used, the additives play a major role in acid etching or proppant transport in heterogeneous reservoirs to attain uniform stimulation, maintain high fracture conductivity, and accelerate post-fracture cleanup. Because of reservoir heterogeneity and the extent of permeability development and net pay sections that need to be stimulated in a horizontal well, ensuring uniform fracture propagation, acid penetration, and proppant placement, effective completion and stimulation design is necessary. The location of perforations is important and can impact fracture growth while the diversion additives in the fracturing fluid ensure that perforation clusters are all treated sequentially, assist and enhance acid interaction or proppant distribution inside the fracture, and increase the effective fracture geometry, contact area, and overall conductivity. The paper highlights the importance of perforation placement and discusses in detail a novel diversion technology and control pressure pumping (CPP) mechanism successfully applied in several high-pressure, high temperature condensate tight gas reservoirs to optimize breakdown, acid penetration, proppant transport, and maximize stimulated volume and well productivity. Several wells have been acid fractured, matrix acidized, or proppant fractured using novel diversion materials and are discussed in this paper. Various diagnostics used to verify stimulation coverage include running production and temperature logs, conducting distributed acoustic and temperature measurements, as well as pumping nonradioactive tracers. Although these wells exhibited a wide range of porosity and permeability variation along the drilled section, each perforated interval was effectively stimulated using novel diversion materials. Compared to offset wells where diversion was not used, wells treated with novel diversion showed a distinct difference in acid etching or proppant placement profiles, thereby confirming their superiority. The total production rate observed was much higher in the novel diversion applied wells.

Abstract Acid Fracturing technique is an alternative to propped fracturing in acid soluble formations. Factors controlling the effectiveness of acid fracturing are the etched fracture penetration and conductivity. Large volumes of acid and the dissolution of large volumes from thefracture faces with excessive acid leak off result in negative net fracturing pressures and less optimized etched fracture length. This paper describes the first application in Middle East area of a nitrogen assisted residue-free fracturing fluid system to successfully stimulate a carbonate formation.

Abstract Mud weight optimization is a key driver in attaining optimum wellbore stability while drilling horizontal wells. This paper demonstrates the role of geomechanical knowledge prior to and while drilling to address wellbore stability related issues to help reduce drilling risk and non-productive time (NPT). To maximize gas production from a tight carbonate reservoir, horizontal drilling and multistage hydraulic fracturing methods have been adopted. For several wells, maintaining wellbore stability has been a challenge without prior geomechanical knowledge of the field resulting in undesired drilling events such as tight hole excessive reaming, stuck pipe, and difficulties while making trips. Even in wells with pre-drill geomechanical analysis for mud weight recommendations, uncertainty in the pore pressure due to depletion along the horizontal section of the wellbore, drilling with one recommended single mud weight (MW) posed great challenge to manage wellbore stability. In this paper, statistical analysis of data is used to investigate root causes of wellbore stability related issues for a number of horizontal wells drilled in the direction of the minimum horizontal stress. The analysis suggests that wells drilled with little understanding of geomechanical properties along the wellbore path encountered significant NPT's compared to those wells where understanding of rock mechanical behavior and in-situ stresses was utilized to make recommendations prior to drilling. In some cases it helped reduce NPT to less than 2% even in exploration wells. Among the successful wells, results from a case study describing the real-time (RT) geomechanics workflow was used to optimize MW enabling drilling the well to the planned target depth. The uncertainty related to pore pressure and intervals of high porosity which creates a significant risk of differential sticking were addressed by incorporating RT data and updating wellbore stability models and providing recommendation to the field operation. The paper demonstrates the role of geomechanics and its impact to drilling operations aimed to reduce operation cost and increase drilling efficiency by eliminating geomechanics-related wellbore stability problems.

Abstract Economic recovery and production of non-associated gas from the tight clastic reservoirs in Saudi Arabia faces some challenges resulting from high bottomhole temperature, high in-situ stress, low permeability, and high Young's modulus and rock compressive strength. Hydraulic fracturing, a necessary means to exploit the tight reservoirs, encounters constrains such as high fracture initiation and treating pressure, risk of pre-mature screen-out, and conductivity degradation with time. A conventional fracturing treatment in such challenging environment necessitates increased polymer loading in fracturing fluids to stabilize fluid viscosity and using smaller size proppant at low concentrations to ensure proppant placement. This results in shorter effective fracture half-length and low fracture conductivity. Reduced contact area decreases production potential. Additionally, high polymer loading is not easily breakable and may create major damage to the proppant pack, thereby substantially reducing fracture conductivity. The challenges compound when the reservoir is relatively tight and often cannot generate enough energy to clean up the injected fracturing fluids. To overcome these challenges, channel fracturing was introduced where proppants are added in pulses in fracturing fluids along with dissolvable fibers creating stacks of pillar-like structure inside the fracture. These proppant pillars stay suspended and are held by the fibers during the treatment. Once the pumping is stopped, the fracture closes on the pillars and the fibers degrade under formation temperature. These pillars hold the fracture open and act as columns; the void surrounding them are essentially stable channels along the entire geometry of the fracture that provide open pathway for hydrocarbons to flow in a near-infinite conductivity environment. The technology also reduces the amount of proppant pumped compared to a conventional treatment, and pulsation of proppant during pumping reduces the risk of an early screen-out.

Abstract Successful production from unconventional reservoirs is made possible by horizontal drilling and reservoir stimulation through multistage hydraulic fracturing along the laterals. Although hydraulic fracturing techniques have been widely used for unconventional gas stimulation, a considerable percentage of perforations do not contribute to production. The objective of this study is to integrate the geomechanical, petrophysical and completion parameters to precisely design hydraulic fracture for better hydrocarbon production. Reservoir characterization and optimizing completion parameters are essential for effective well design to improve staging and perforation placement. Challenges in the design of hydraulic fractures include the proper placement of fracturing ports, perforations, and location of isolation packers. The challenges are due to the large variability in fracture gradients, mechanical and reservoir properties, and petrophysical characteristics along the lateral. Industry experience shows that injection pressures required to fracture the formation (fracture gradient, FG) often vary significantly along a well and that there can be intervals where the formation cannot be fractured successfully by fluid injection due to high in-situ stress. Geomechanical and petrophysical evaluations providing rock anisotropy and anisotropic stress properties along the wellbore play a fundamental role in completion and hydraulic fracture design. The paper shows how geomechanical and petrophysical properties from open-hole logs and sonic anisotropy evaluations are integrated to compute reservoir quality (RQ) and completion quality (CQ). Intervals with similar properties are grouped to better understand and optimize hydraulic fracture design and operations. This optimization procedure has been applied in a borehole within a potential shale gas reservoir targeting the hot shale facies formation in Saudi Arabia. Application of this technology resulted in successful completion with optimum fracture stages and perforation clusters positioning thereby improving the initial flow capacity of the well.

Technology Focus With the significant drop in oil price and slowing down of the world economy, one might think many petroleum-related technology items will stall or fade out. Although it may be true for those technologies that are “good to have but not essential,” the oil-economy downturn will not affect the areas where research, development, and application of novel technologies are absolutely necessary for the commercialization of hydrocarbon. When we look at world statistics, we find hydraulic fracturing being used as a key operational technique and enabler in the majority of oil and gas wells to produce them economically with long-term stabilized rates. Any major cut in fracturing or stimulation technology will severely affect world production outlook and, consequently, world energy and therefore is unlikely to happen. Because of the success achieved through hydraulic fracturing, the industry strives relentlessly to maintain the cutting edge in development of novel and innovative technologies and their field applications. Major progress has been made in well completions to accommodate well-stimulation treatments. These include multistage-fracturing (MSF) completions, both openhole and cased; screen tubulars to prevent proppant and sand flowback; and disintegrating dropdown isolation balls and in-tubing plugs, all of which have contributed to fracturing efficiency and cost-effectiveness. A stimulation item worth mentioning is the energized fracturing processes with liquid carbon dioxide (CO2). If the economics works out, the technology is particularly helpful in treating partially depleted reservoirs where natural flowback after fracturing is difficult. For such reservoirs, when fractured with conventional fluids, nitrogen (N2) -assisted lift is needed for the initial startup, resulting in additional time and expense. Liquid CO2 can eliminate or curtail the use of water and simultaneously provide both the hydrostatic head and the energy to clean and lift the well without N2 intervention. One main challenge faced in the development of tight and ultratight reservoirs is the ability to fracture the formation and produce at commercial rates. The challenge occurs particularly in deep reservoirs exhibiting high fracture gradients. In openhole MSF, the placement of isolation packers and fracturing ports is important to pump a successful treatment. In plug-and-perforate MSF, the proper location of perforations and clusters is important. In either completion system, if the induced fractures are not initiated in the right place, very high breakdown pressures may be encountered that can exceed completion limitations. On the other hand, when perforations are placed in nonsweet intervals, the production may suffer even when fractures can be induced. Industry statistics have shown that, many times, more than 50% of the perforation clusters are nonproductive because of poor placement of perforations, thereby reducing production efficiency significantly. Therefore, it is absolutely necessary to perform a complete assessment and evaluation— from drilling to production— to ensure well placement; landing point; azimuth; trajectory; and, most importantly, packer and perforation/port locations. A model that fully integrates drilling dynamics, real-time geomechanics, geosteering, completion placement, production forecast, and rate sustainability is an essential tool for successful fracturing operations. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 174026 Impact of Remaining Water in Hydraulic Fractures on Well Productivity—Field Examples From Saudi Arabian Sandstone Reservoirs by Zillur Rahim, Saudi Aramco, et al. SPE 174060 Application of Microproppant To Enhance Well Production in Unconventional Reservoirs: Laboratory and Field Results by Jeff Dahl, Devon Energy, et al. SPE 177953 How To USE Hydraulic- Fracture Interference To Improve Unconventional Development by Basak Kurtoglu, Citibank Global Energy, et al. IPTC 17731 A Rigorous Correlation for Quantification of Skin in Preanalysis of Hydraulic Fracturing by Rizwan Ahmed Khan, King Fahd University of Petroleum and Minerals, et al.

Abstract In most cases several folds of increase in production after a fracturing treatment is sufficient testimony to the success of the technology and its application in the particular well or field. A cursory look at a post-frac, pressure transient analysis (PTA) will show a stimulated well condition and validate the achievement. For a proper assessment of well potential this approach may be inadequate. The fracture geometry, conductivity, phase flow through the reservoir, reservoir quality, completion practices and pressure behavior under the boundary conditions all contribute to a well's performance. With all these factors considered, the post frac production results may be significantly different from expectations. To encompass this, the preferred methodology would be to benchmark the production from different fractured wells to have a valid comparison and then optimize the methods. Production-history matching through reservoir simulation is a very effective tool in meeting this challenge. Many subtle features of the reservoir get highlighted in relation to hydraulic fracturing with the dominant component being the fracture itself. This paper examines several successful wells, which unexpectedly fell below the benchmark. The study investigates whether the hydraulic fracture underperformed or the post-frac activities contributed to low well deliverability. Conventional hydraulic fracturing and the newer technique of channel fracturing were part of this analysis. The post-frac flowback procedures had a significant impact on the productivity of the wells. The presence of condensate brought its own set of challenges. In the long term, it was also interesting to note how the wells recovered after these damages. This paper will provide an insight into this investigation.

Abstract Strong demand for energy during the last decade influenced the increase in horizontal wells with multiple fracture stimulations. The strategy helped in increasing oil and gas production to meet the demand of internal and external markets. Wells with transverse fractures have been the first option in low-permeability shale, sandstone, and carbonate formations. This is to increase the number of independently growing fractures thereby increasing the contact area. The fractures propagate transverse to the wells as they are drilled and completed in the direction of maximum in-situ stress (σmax). Many authors, however, have reported that in sandstone reservoirs, the efficiency of transverse fractures is affected by proppant pack permeability reduction due to non-Darcy flow. The study focuses on the best completion option for gas wells in terms of production performance and logistics that will ensure optimal field development.

Abstract Multistage fracturing (MSF) of horizontal wells has proven very successful in the development of moderate to tight gas reservoirs. To make MSF treatments fully successful, the well configuration must be carefully designed. One important point to consider is the direction of well azimuth. Since the induced fractures always propagate in the direction of maximum in-situ stress (σmax) direction, drilling wells towards the minimum stress (σmin) will generate transverse fractures. This scenario allows multiple independent fractures as there is no overlap between fractures. When a well is drilled along the maximum stress direction, the fractures propagate along the wellbore axis. In such case one fracture can overlap the adjacent fracture and thereby the number of independent fractures will be fewer. Wells with transverse fractures are usually the first option in low-permeability shale, sandstone, and carbonate formations. This is because the reservoir to wellbore contact area is significantly increased as the number of fractures induced is increased. Many authors, however, have reported that in sandstone reservoirs, the efficiency of transverse fractures are affected by proppant pack permeability reduction attributed to non-Darcy flow. This study focuses on the best completion option for gas wells in terms of production performance and logistics to help ensure optimal field development.