Calcium sulfate has been one of the major scales which cause many significant and serious operating problems in producing oil/gas wells and in water injectors. Impermeable hard scale deposits of calcium sulfate can severely impair the formation permeability or lead to down-hole equipment failure. Typically, preventative treatments, such as use of scale inhibitors, are the best economical methods for calcium sulfate mitigation. However, application of a cost-effective treatment is needed, in case of emergency, when calcium sulfate precipitation occurs. A comprehensive lab investigation was conducted in order to assess the effectiveness of several remedial methods for calcium sulfate removal. This work shows the amount of calcium sulfate dissolved after its exposure to different reactive fluids at 25 and 50°C. In addition, it discusses the effect of different factors on the efficiency of each remedial treatment. These factors include: pH, temperature, reactive fluid concentration and presence of magnesium/iron ions. Based on obtained results, several new findings were identified. The presence of gypsum (CaSO4.2H2O) has negative impact on the performance of mud acid treatments. After initial dissolution of gypsum in live mud acid, dissolved calcium will precipitate as both calcium fluoride and calcium sulfate in spent HCl/HF solutions. Similarly, gypsum has higher solubility limit in live HCl acid compared to its spent solutions. This resulted in re-precipitation of calcium sulfate in spent HCl. This solubility trend of gypsum in acidic solutions could result in severe formation damage. Live acids can initially dissolve any precipitated calcium sulfate solids in wellbore area and then it will re-precipitate in the formation rocks as the acid spends. Gypsum has higher solubility limit in EDTA solutions, compared to acidic solutions. No re-precipitation of calcium sulfate occurred in these solutions due to the fact that calcium ions exist as complex ions and not free to interact with other ions. The dissolving power of EDTA was found to be a function of the solution pH value. Higher dissolving power of EDTA for gypsum was observed at high pH values. The presence of both magnesium and iron (III) ions had negative effect on gypsum dissolution in EDTA fluid. Compared to magnesium, iron (III) ion resulted in significant decrease in gypsum solubility in EDTA. Dissolved magnesium ions in EDTA solutions could re-precipitate as magnesium sulfate when gypsum is dissolved. This re-precipitation is more at low pH EDTA solutions.

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.

Acid fracturing treatment performance is largely determined by the achieved effective etched fracture length. Evolution of fracture length during such treatments leads to progressively increasing the acid leakoff rate up to a point when the fracture stops extending. Zonal coverage and fluid loss control in naturally fractured carbonate reservoirs with high permeability contrast are the key challenges during acid fracture treatment.Nonreactive and reactive polymer based fracturing fluids and diverters were historically accepted as systems that could efficiently control fluid leakoff. The performance of such fluids relies on wall building fluid loss additives, such as polymers. Their deposition on the fracture face forms filter cake that decreases fluid leakoff into the formation. Filter cake on the etched fracture wall could cause skin. Nondegradable particulate fluid loss additives used in naturally fractured reservoirs can be a good leakoff control tool; however, particulates could permanently shut natural fractures off and obliterate their production contributions. Finding the right balance between induced fracture damage and conductivity is a challenge, and avoiding this damage by using nondamaging fluid with major fluid leakoff control properties is the logical problem solution.A novel fiber laden polymer-free self-diverting acid system was introduced in Saudi Aramco as an acid fracturing diverter to control fluid leakoff, and enhance the diversion process by combining the aspects of both particulate and viscosity based diversion techniques. The fluid system has a distinct advantage in that it does not contribute to formation damage because the viscoelastic surfactant will breakdown upon contact with hydrocarbons, and the fiber will degrade with time and temperature.More than 25 acid fracture treatments using the novel acid system have been successfully implemented in gas bearing carbonate reservoirs in Saudi Arabia. Unlike the approach used in acid fracture treatments using conventional fluid systems, the degree of diversion was dynamically adjusted to maintain the treating pressure above the fracturing pressure throughout the entire period in these treatments. The bottom-hole pressure (BHP) measurement confirmed superior fluid leakoff control leading to an outstanding diversion performance with excellent gas production increments.This paper provides details about treatment design, field implementation, and post-stimulation performance for two out of the more than 25 wells treated using this novel acid system.

A recent series of tight gas discoveries in the Amin formation of the greater Fahud area represents some of the most exciting exploration success of this decade in the Sultanate of Oman. The structures have been evaluated as containing very significant amounts of gas locked in a challenging deep and hot environment requiring hydraulic fracture stimulation. Since their discoveries, the two primary challenges have been difficult breakdown of the formation and limited proppant placement during stimulation attempts. The early experience in the exploration and appraisal campaigns from 2009 to 2014 has led to fracture designs with conservative proppant amounts that could limit the full potential of the field. Several geomechanical studies have been commissioned in the past to guide completion strategies in well placement, perforation, and fracture stimulation design.The objectives of this study were to model hydraulic fracture initiation and breakdown in the three Amin zones (upper, middle, and lower) to provide some theoretical understanding of the impact of the different parameters on the observed field breakdown pressures. In agreement with field observations, the model showed that lowering the viscosity of the pad has a major impact in lowering the breakdown pressures. Consequently, current best practices include formation breakdown and hydraulic fracture propagation with low-viscosity fluids followed by proppant placement with high-viscosity fluids. When applied to tight gas formations in the Sultanate of Oman, the hybrid fracturing evolves from conventional designs for the purpose of successful fracture initiation, while still placing a successful job.

Sand in Saudi Arabia is easily accessible through surface mining or excavating large dunes that are API approved, but like many sands around the world, lacks the necessary strength for fracturing high stress formations. To exploit the sand, a novel engineered workflow, enabled by the flow channel fracturing technique was established for qualifying and implementing Saudi Arabian sand to fracture stimulate the tectonically complex ultra-tight "T" carbonate formation. Channel fracturing does not depend on the proppant pack to provide conductivity, rather on the creation of stable, open flow channels. Therefore, carefully selected sand that can keep the channel structure open under stress can be a viable material to replace up to 80% of the ceramic proppant materials. The local sand used was qualified through unique lab testing procedures to understand the pack behavior under stress, the pillar erosion under stress, and the effects of stress on long-term conductivity. Once qualified, a design methodology was applied to optimize the fracture geometry and pillar placement for the initial field test in Well-A, a horizontal lateral where high strength proppant (HSP) is traditionally used. A total of six channel fracturing stages with local sand — 40% of the total stages — were placed as per design in two sections of the 15-stage lateral along with four conventional and five channel fracture stages using HSP. A multi-month cleanup and well test period resulted in Well-A being one of the best producing wells in the basin — 26% higher initial production than the next best well. A production log showed sand stages to be producing an average of 15% higher total production than HSP stages. An oil tracer analysis revealed sand stages produced an average of 62% more condensate than HSP stages. This initial production response confirms at least par production with no detrimental effects for channel fracturing with local sand compared to techniques using HSP, with the potential for improved production. This qualified and field tested completion methodology allows for the potential replacement of a significant portion of imported ceramic proppant with locally sourced sand, an abundant and accessible resource inside the Kingdom of Saudi Arabia and beyond. The benefits of this technology include cost reduction, placement improvement, at least par production and the maximizing of in-country content and value.