Hydraulic fracturing activities in tight gas wells in Saudi Arabia have been exponentially increasing to meet domestic demand for natural gas. During each fracturing stage, up to 125,000 gallons of groundwater is currently being used. The need to reduce groundwater usage during fracturing treatments has been set as a priority, and alternative water sources for fracturing applications that can significantly reduce groundwater usage have been intensively explored. One such alternative water source is seawater as a base fluid for hydraulic fracturing. The primary challenge for this application is the tendency for scale precipitation due to the high sulfate content in seawater and its potential incompatibility with formation water. Without proper prevention and mitigation measures, this scale precipitation can induce formation damage and reduce the fracture conductivity. To minimize scaling tendencies, an in-house multidisciplinary team has performed extensive collaborative research to identify a scale inhibitor appropriate for Arabian Gulf seawater and formation water. Scale precipitation can be further mitigated by filtering the seawater with a nanofiltration system to dramatically reduce the sulfate ion as well as lower the calcium and magnesium ions. The successful application of seawater-based fracturing fluid in Saudi Arabia opens up the door to minimizing consumption of groundwater in hydraulic fracturing operations. Millions of gallons of groundwater could be saved and development of sustainable water resources could be achieved. This paper will describe the optimization of a scale inhibitor and fracturing fluid system, the selection of the nanofiltration system, and the first field applications of the seawater based fracturing fluid system in high-temperature gas wells in Saudi Arabia.

Stimulation of sandstone reservoirs usually involves the use of a hydrofluoric-based acid (HF). Hydrofluoric acid reacts rapidly with clay minerals and slowly with sand particles. Stimulation of sandstone formations is a challenging task because it involves several chemical and physical interactions of the acid with the formation. Some of these reactions may result in formation damage. Retarded HF (RHF) acids are less reactive with the rock and normally result in deep acid penetration into the formation. Three RHF acids that are based on boric acid (H3BO3), aluminum chloride (AlCl3), and a phosphonic acid were examined. Several tests were conducted to evaluate interactions between RHF acids and sandstone rocks. Static solubility tests were performed using sand particles and clay minerals at 25 and 75°C. Chemical analysis of spent acids was extensively used in this study. Acidizing sandstone reservoirs using mud acid is a complex process where dissolution and precipitation occur simultaneously. The process is even more complicated when RHF acids are used. The results of this study indicate that the composition of spent acid strongly depends on the retarded system used. Dissolution of clays is generally reduced when a form of RHF is employed. However, increasing the soaking time caused precipitation in all RHF acids examined. Some of the RHF acids precipitate materials that are not encountered when regular mud acid is used. This paper addresses several chemical interactions that have not been addressed previously in the literature. Introduction Sandstone formations consist of four main categories of minerals: silica (quartz), feldspars, clays, and carbonates. Mud acid is a mixture of hydrochloric acid (HCl) and hydrofluoric acid (HF). This mixture can be prepared at different HCl:HF mass ratios to prevent the formation of damaging precipitates.1 The goal of retarded HF acids is to decrease the reaction rate of HF with alumino-silicates (clays and feldspars) to achieve a sufficient acid penetration into the formation and remove deep damage. A through literature review indicates that there are at least three main retarded HF systems. A brief summary of each acid system is given below. The first system (BRHF) is based on fluoboric acid (HBF4).2 Fluoboric acid can be generated by the reaction of boric acid (H3BO3) with HF (Eqs. 1 & 2). Fast Reaction:Equation (1) Slow Reaction:Equation (2) As HF spends on siliceous minerals, HBF4 hydrolyzes to regenerate HF (Eq. 2).3–4 The second system (ALRHF) is based on aluminum chloride (AlCl3).5 Aluminum chloride reacts with HF to form aluminum fluoride species (Eq. 3).Equation (3) As HF spends on siliceous minerals, AlF4 - hydrolyzes to regenerate HF (Eq. 4).Equation (4) The third system (PRHF) is based on using a phosphonic acid complex that contains five hydrogen atoms. This acid reacts with ammonium bifluoride to produce an ammonium phosphonate salt and HF. The fluoride ions are provided by the ionization of dissolved ammonium bifluoride. To form HF, hydronium and fluoride ions combine. However, the hydronium ion concentration is low because of the weak nature of the phosphonic acid. Therefore, equilibrium is created by the buffering action of the weak organic acid and ammonium phosphonate salt.6 The objectives of this study are to:examine the solubility of sand and clay minerals in the three retarded HF systems, andcompare these systems with full strength regular mud acid (RMHF).

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper discusses a new technique that was used to evaluate matrix acid treatment conducted on a cased water disposal well in a carbonate reservoir. The technique relies on calculation amount of corrosion products and minerals dissolved by the acid. It was used to calculate the amount of iron dissolved by the acid and the live acid present in the flowback following the pickle treatment. Chloride ion concentration was used to determine the degree of mixing between the spent acid and formation brine. The degree of mixing was then used to calculate the volume of the produced spent acid and the amount of minerals (calcite and dolomite) that were dissolved by the acid. The chemical efficiency of the acid, defined as the actual amount of calcite dissolved by the acid/the theoretical amount of calcite that the should dissolve, was finally determined.

Barium Sulfate, barite is commonly introduced into the oil and gas wells during drilling when used as weighting agent but it also can be formed at wellbore tubular during production as scale. After drilling, the barite in the wellbore and in the filter cake can cause erosion of well tubing during production, and should be removed. Dissolving and removing barite is a challenge because of its low solubility in water and hydrochloric acid. It can be removed by mechanical approaches, which includes scarping and jetting with foamed or viscose fluid to carry the heavy barite solid. In this study, a new barite dissolving formulation was evaluated for its dissolving power and as barite and barite-based drilling fluid mud-cake removals. The dissolution rate at dynamic condition and in the presence of calcium carbonate was also evaluated for more than 72 hours reaction time. The study-testing scheme aimed to identify: the optimum solid to liquid ratio for maximum solubility, optimum soaking time at downhole temperature and solubility of mud-cake at optimum ratio and soaking time. Careflooding was also carried out to determine the rock-dissolver interaction. The interaction between stimulation chemicals and formation rock is essential in order to understand these chemicals efficiency. The study results showed the average barite and mud-cake solubility was 276 and 167 lb/1000 gal in 24 hours at 270°F, respectively. 60% of the dissolved barite occurred in the first 5 hours soaking time. In the presence of calcium carbonate, the dissolution rate was dropped by almost 40%. The reduction started to be significant after 8 hours of soaking. Multi-stages treatments using 10 gallons of the dissolver per 1.0 lb of barite with 5 to 8 hours soaking time are expected to be more effective than one-stage treatment with a long soaking time.