Recently Saudi Aramco and international companies started an aggressive gas exploration campaign in tight gas sandstone formations. In most of the cases the prospective tight gas producing zones were discovered at a depth below 20,000 feet where the stress and temperature are extremely high and the reservoir permeability conditions are low; being necessary in all cases to fracture stimulate each horizon to define the fluid and evaluate productivity. The extreme stress and temperature conditions are actually one of the main challenges to perform fracture stimulations on this type of formation, this because the fracturing fluid needs to be stable, induce minimum damage and have good proppant transport capabilities at high temperature conditions. As a part of the referenced exploration activity in the first quarter of 2008 Saudi Aramco has the challenge to perform a proppant fracture stimulation in a deep tight gas on shore sandstone formation where the temperature and stress conditions (375° F and 1.1 psi/ft at 20,000 feet) exceeded the working pressure capability of the available equipment and the existing fracturing fluids application limits. To answer the referenced challenges and knowing that 20,000 psi fracturing equipment is not available in the area an extensive laboratory evaluation was done to design a new high density fracturing fluid. After a lengthy laboratory evaluation, we were able to select a regional supplier for the 1.48 specific gravity (12.3 lb/gal) heavy brine used as the base fluid and prepare a user friendly cross linked fluid for the referenced field application. The new fluid system was successfully mixed and pumped in the field enabled the treatment of the well through lower surface treating pressure with conventional 15,000 psi equipment, lower horsepower requirements, and a safer work environment. The paper summarizes the well conditions, extensive fluid qualification testing, procedures, and specially learned lessons during the referenced first field application of the new fracturing fluid system. Introduction As Saudi Arabia increases their demand for natural gas inside the Kingdom, ongoing reservoir targets are moving increasingly to more challenging reservoirs which exhibit low permeability of <0.01 md. Reservoir pressure ranges from low or can be extremely high (11–13,000 psi) and the high temperature makes obtaining reservoir data increasingly difficult due to tool limitations. Two particular formations which have recently received attention is the Sarah and Mid Qusaiba formation. These two reservoirs have been penetrated over 25 times in Ghawar and western Rub' Al Khali areas by Saudi Aramco and the International Oil Companies. Reservoir quality is typically moderate to poor (5–15% porosity); natural fractures are thought to significantly enhance deliverability in wells. Recently hydraulic fracturing was included in the testing of these formations which resulted in short term rates of 3–5 mmscfd. Hydraulic fracturing these formations are increasingly challenging due to mechanical limitations on the completion assembly and surface equipment. Maximum surface pressure limitations of 15,000 psi with a maximum bottom hole pressure limitation required the use of 12.3 lb/gal sodium bromide (Nabr) brine. Heavy brines have been successful in the deep Gulf of Mexico frac packing however they have never been applied to a tight gas reservoir. Development of this fluid was targeted to local material resources, fluid stability at 375º F temperature, proppant transport capability, and minimal formation damage. The new fluid was extensively tested to ensure it would perform as required in the field.

Use of 16-in. vertical sections in onshore deep gas drilling operations in Saudi Arabia presents challenges with a high risk of total drilling fluid loss in interbedded formations. The formations comprise carbonates, limestones, shales, anhydrites, and abrasive sandstone with pyrite inclusions, where the rock hardness is 10 to 15 kpsi unconfined compressive strength (UCS). To minimize the risk of loss, the high bentonite mud system is implemented. The bit consumption averages two tungsten carbide insert (TCI) bits per section, and high average dull grading conditions are observed (IADC 3-4-WT), coupled with low rate of penetration (ROP) performance across the whole section. Though an in-depth offset well study, including bottom-hole assembly (BHA) analysis, bit dull condition review, evaluating the high bentonite mud effect, and the UCS formation trend, the potential to drill the 16-in. section in a pilot well in a satellite field (using hybrid bit technology) was determined. This paper outlines the development of the best drill bit technical solution, optimizing the use of crushing (TCI inserts) and shearing effect (polycrystalline diamond compact – PDC) cutting structure configuration to drill the section in the minimal time and cost possible. The results observed in the pilot well confirmed that one hybrid bit had the ability to drill the total section. A 138-percent increase in the rate of penetration (ROP) versus relevant offsets, and a decrease 2.3 operational days and 50% cost per foot reduction. The hybrid bit reached the total depth (TD) section without any operational issues, where the risk of losses was minimized, and a proportionate normal dull condition in the cutting structure was observed. The technical compatibility of the hybrid technology was demonstrated with outstanding performance for the operator.

Gas Migration through cement columns has been an industry problem for many years. The most problematic areas for gas migrations occur in deep gas wells. To control gas migration, cementing practices should be optimized. The cementing practices include cement composition, drilling fluids composition, spacer composition and operations such as pumping procedure and pressure testing. Gas migration can occur due to settling in high-density cement slurries. Cement densities required to successfully cement the zone could be as high as 170 pcf (Pounds per Cubic Foot). As cement slurry sets, hydrostatic pressure is reduced on the formation. During this transition, gases can travel up through the cement column resulting in gas being present at the surface. Gas migration problems can also occur due to poor displacement. Spacers, cements and drilling fluids should be designed and tested for compatibility for good displacements and bonding. Different types of spacer is required for each type of drilling fluid such as salted drilling fluid or oil based fluids. Testing should include running rheology tests, thickening time tests and compressive strength development tests. Cement shrinkage is another factor that can cause gas migration problems. Expansion additives are usually added to overcome this problem. However, attention should be made to optimize the concentration and type used to avoid over expansion behavior that can cause micro cracks in the cement matrix. Different cycling effect in temperature and pressure can cause gas migration channels due to creation of micro cracks. This paper highlights some of the effort to prevent casing/casing pressure leaks from deep gas wells.

Sustained casing pressure, otherwise known as casing-casing annulus (CCA) pressure, is a common problem encountered in the deep, high pressure, high temperature (HPHT) gas fields of Saudi Arabia, and in many other locations globally. Although many solutions have been tried in these fields over the years, none of the existing solutions have proven to be 100% effective. A new solution has recently been implemented in Saudi Arabian gas fields that features a combination of heavy-weight cement blends greater than 21ppg and a polymer resin to improve the mechanical properties of the cement, especially the shear bond, to prevent the CCA pressure. Polymer resin is also resistant to hydrocarbons, acids, and salts, enabling the cement-resin system to be placed in harsh environments. This resistance will help to maintain a dependable barrier throughout the life of the well. This paper presents a case history of the application of this heavy-weight cement-resin (HWCR) system in the Saudi Arabia Harradh field where the failure of a differential valve (DV)packer meant that there would be no redundancy backup should the cement fail to provide a full barrier in the annulus. The paper describes the process used to design the HWCR system and how its application is critical to the success of the job.

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