The Khuff formation is a late Permian age heterogeneous carbonate sequence that underlies the massive Ghawar field in eastern Saudi Arabia. The Khuff is subdivided into four separate intervals (A through D), though production is primarily from the B and C intervals. Since its initial appraisal in the late 1970s, the majority of Khuff development activity has been focused in the Khuff-C reservoir, where single and multistage matrix acidizing treatments have been the predominant stimulation technique. As domestic gas demand in Saudi Arabia continues to rise, unrelenting efforts are underway to develop the tighter Khuff-B areas while sustaining production levels from Khuff-C wells. As a result, an increasing number of wells have been drilled and completed in the Khuff-B reservoir. The latest trends in the development of these tight gas Khuff wells include multistage acid fracturing to optimize the stimulation treatments. Various drilling, completion, and stimulation techniques have been utilized in the Khuff development since its inception. Some of the variants analyzed to determine impact on production include: type of stimulation treatment, hole azimuth, completion isolation system, and number of stimulation stages per well. In addition, treatment design parameters were analyzed. Particular attention was paid to performance trends from Khuff-B wells where improved technical solutions were required to address challenging reservoir characteristics. The results of this analysis demonstrate that multistage fracturing (MSF) technologies made a positive impact on Khuff development—with improved production results over time. Trends also highlight an increase in stimulation stage count and a wider range of stimulation treatments with the application of new technologies. The analysis identified the key production drivers in the Khuff and ways to improve production of future wells drilled in the formation. Continued use of multistage fracturing has proven very successful in Khuff reservoir providing substantially higher rates and sustained production.

Hydraulic fracturing is required to commercially produce low to moderate permeability gas reservoirs. The selection of fracturing fluids, additives, and proppant types are major components when designing and implementing a hydraulic fracturing treatment. A viscous, unbroken fracture fluid that remains after the treatment compounds the effects of fracture face skin and causes severe deterioration to proppant conductivity. With the advancement of technology, many novel fracture fluid systems are available in the industry with reduced polymer concentration to preserve reservoir and proppant integrity. The advantages of these fluids include less formation damage, low cost, and reduced treatment pressure. Subsequent to the fracture operation, an aggressive breaker treatment is often necessary to effectively clean up the fracture and restore proppant conductivity. Proppant conductivity plays a tremendous role in the post-fracture production enhancement and any damage left from the fluids can impair well potential considerably. Similarly, correct choice of proppant based on the rock strength, reservoir fluid properties, expected production rate, pressure, and temperature is important. Proppant type and scheduling determine the ultimate propped fracture geometry that controls the gas flow from the reservoir to the wellbore. Application of new technologies in combination with better job design to obtain improved results in the deep sandstone reservoirs of Saudi Arabia is ongoing. In the process of optimization, fluids along with its gel type, polymer concentration, and additives have been modified and changed to provide better results. Similarly proppant size, types, and schedule have been optimized. Different types of aqueous-based fracturing fluids used with various polymer loadings as well as the use of hybrid systems and viscoelastic fluids (VES) used in deep and high temperature reservoirs are currently in use. Several case studies provided in this paper demonstrate how the critical fracturing parameters have progressed with time, been customized, and made to fit the reservoir conditions to make a noticeable impact on well productivity and recovery.

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.

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.

Saudi Aramco is developing several gas fields in the Eastern Province of Saudi Arabia by drilling horizontal wells in the Khuff and pre-Khuff tight carbonate and sandstone formations. To date, many wells have been drilled in the maximum horizontal stress direction with virtually no wellbore instability occurring during the drilling operation. When these wells are hydraulically fractured, the fracture grows along the wellbore in the direction of well azimuth. To avoid overlapping of two adjacent induced fractures and thereby communication between stages, only 2-3 multi-stage fracture treatments can be performed. Depending upon the length of wellbore-reservoir contact, reservoir development, and stress barriers, more than four fracture treatments can become redundant or even cause premature screen-out in proppant fracture treatments.Wells drilled in the direction of minimum horizontal stress are potentially more favorable from the perspective of reservoir development and optimal production. In such a situation, hydraulic fractures grow transverse to the wellbore axis allowing multiple fractures to be placed without the possibility of fracture overlapping. Consequently, few wells that have been drilled in the minimum horizontal stress direction encountered several drilling-related problems, such as stuck pipe, breakouts, and breakdowns. A comprehensive study was conducted to overcome the wellbore stability issues and investigate feasibility of drilling wells in the minimum horizontal stress direction. Correct mud weight (MW) prediction is one key factor during the drilling stage to keep the wellbore stable and deliver good borehole geometry to run multi-stage fracturing assembly without complication. Multiple transverse hydraulic fractures easily created in such wellbore geometry maximize reservoir contact area and increase productivity of the low quality tight reservoir.The key objectives of the study were to define a safe MW program for the horizontal section of the planned wells by conducting a wellbore stability study, and to determine a real-time strategy to mitigate and/or manage wellbore instability problems as they arise. The scope of work included root cause analysis of drilling events, development of Mechanical Earth Models (MEM) for offset wells, integrating sections of the mechanical earth model from the offset well to the planned well trajectory and a safe MW program for planned well.