During the past several years (i.e., 2006 to 2014), the US transformed the development of shale oil and gas from slow and steady into a shale gas boom by combining two already existing technologies—multistage hydraulic fracturing and horizontal wells. This helped the US once again be energy-independent regarding natural gas supply (Charlez 2015). Inspired by such success, the Kingdom of Saudi Arabia and the Middle East region are meeting the increasing energy demand by following similar steps (Bartko et al. 2012). Large stage sizes in hydraulic fracturing and horizontal drilling long laterals require large quantities of freshwater. Despite the fact that the Arabian Peninsula lacks freshwater resources, fresh water is still consumed by the oil and gas industry in the region. Conversely, seawater is plentiful and should substitute for freshwater in unconventional resource operations. However, the high salinity of seawater raises many chemical challenges in developing design criteria for fracturing fluids. To help mediate this problem, this paper studies the chemistry of developing seawater-based fracturing fluids using two types of polymers as gelling agents and compares results to already existing freshwater-based fracturing fluid data under different conditions. Various seawaters from around the world were compared to Arabian Gulf seawater and its various compositions throughout the year. The local seawater's high total dissolved solids (TDS) measurement is 54 000 mg/L and includes sulfate (>4000 mg/L), calcium (>600 mg/L), and magnesium (>1700 mg/L). These are the major ions that cause delayed hydration, alteration of the crosslinking mechanism, and high scale formation, along with barite (BaSO4). Moreover, the paper presents a better understanding of fluid behavior by studying the effects of sulfate (>4000 mg/L), calcium (>600 mg/L), and magnesium (>1700 mg/L) individually to observe fluid stability at high temperatures in both polymers.

As part of the continuous efforts to save freshwater resources in the Middle East, seawater-based fracturing fluid offers a high-potential solution to help save millions of gallons of fresh water while developing fracturing fluids for hydraulic fracturing applications. Scale deposition is one of the major technical challenges for fracture stimulations using seawater-based fluid. To understand the scale deposition and mitigation for fracturing using seawater-based fluid, a series of dynamic and static performance, compatibility, and thermal stability tests were conducted. Results showed that harsh scale forms with mixing raw seawater and high total dissolved solids (TDS) tested formation water at higher temperatures under dynamic and static conditions. Scale inhibitors cannot effectively inhibit scale deposition in such harsh scaling conditions because of the issues of compatibility and performance at static conditions. Nanofiltration of seawater is introduced to remove most of the sulfate ions in seawater and help significantly reduce the scaling tendency when mixing with high TDS formation water during fracturing treatments using seawater-based fluid. Combining the nanofiltration technique and scale inhibitor application, the scale issue during fracturing using seawater-based fluid can be effectively mitigated and was determined to be suitable for field application. The scale inhibitor showed good compatibility with nanofiltered seawater. The dynamic scaling tests were successful when the proper scale inhibitor and optimum concentration were used, while the static tests did not form any precipitation. Thermal aging resulted in a color change for all tests, as expected, and the performance of the thermal-aged scale inhibitor was evaluated. This paper provides insight into the scale deposition and inhibition for fracturing treatments using seawater-based fluid at high-temperatures up to 300°F and furthers the effective strategies to address the scale issue during fracturing using seawater-based fluid.

The loss of circulation is a big problem in drilling operations. This problem is costly, time-consuming and may lead to a well control situation. Much research has investigated the effectiveness of using different chemicals as lost circulation material (LCM) to stop mud and cement slurry losses. However, there remain many limitations for using such LCM types, especially when it comes to field applications. This paper presents a new high strength lost circulation material (HSLCM) that could effectively be used for managing severe lost circulation cases. The HSLCM could easily be pumped into the thief zone where it forms a gel that solidifies after a setting time to provide sealing between the wellbore and the thief zone. With this technique, the material stops the circulation losses, and hence enhances the well bore stability by reducing the well bore stresses. The HSLCM has a high compressive strength and it has a high acid solubility of around 96%. Because the HSLCM has high tolerance towards contamination, it can be utilized with water-based mud or invert emulsion-drilling fluids, hence providing a wide window of applications with the drilling fluids. In this study, laboratory experiments were conducted to evaluate the rheology, thickening time, compressive strength, and acid solubility of the HSLCM. The results showed good performance for the HSLCM as LCM. In addition, a case field study is presented which shows a successful field treatment for severe losses.

One of the most serious oilfield problems is scale deposition, particularly when two incompatible waters are involved. The control of scale deposition in high-pressure/high-temperature (HP/HT) wells has been challenging because most scale inhibitors lose effectiveness at high temperatures as a result of molecular instability. Hence, in the context of adapting to the continuous challenges of the oil and gas industry, along with the need to preserve freshwater resources in the Middle East, an in-depth study of the scaling results of mixing fracturing fluid developed using nanofiltered (NF) seawater with formation water containing high total dissolved solids (TDS) under HP/HT conditions is discussed. A series of dynamic experiments was performed using a DSR-6000 dynamic scale loop at 330°F and 3,000 psi. Additionally, static experiments were conducted at room temperature and 330°F for 2 and 24 hours, respectively. For both dynamic and static tests, two mixing ratios were tested: 80:20 and 50:50 mixtures of NF seawater:formation brine. The 80:20 mixing ratio represents the worst-case scenario according to scale advisor software results. Moreover, regained core permeability at 300 and 330°F and retained proppant pack conductivity tests were also performed. Results demonstrated that, for dynamic scale loop testing, the lowest concentration of scale inhibitor tested (250 ppm) achieved the passing criteria along with all higher concentrations for both mixing ratios. The static tests were also successful, with no precipitation formed. Regained core permeability was in the range of 77 to 89%. Finally, retained proppant pack conductivity result of 56% indicated good cleanup properties for NF seawater.

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