Currently, inverse emulsion (water-in-oil) polymers are the most widely applied friction reducers for hydraulic fracturing. While oil-external friction reducers are the industry standard, they are limited by their tolerance to water containing high Total Dissolved Solids (TDS), requiring low TDS in blended waters to achieve adequate friction reduction without the addition of an external surfactant to aid in hydration. To increase operational efficiency and reduce impact on local infrastructure, operators desire to recycle the maximum amount of produced water. To meet this goal, a friction reducer that functions unassisted in high TDS water is needed. This paper describes the use of a Dispersion Polymer Friction Reducer (DPFR) in the Marcellus Shale that addresses this need. A salt-tolerant, water-based friction reducer was developed to allow well operators to reuse high TDS produced waters encountered in the Marcellus Shale. Both lab and field experiments were carried out to assess the effectiveness of the new friction reducer. The data presented in this paper show several advantages of the DPFR: (1) conservation of fresh water sources, (2) greater flexibility in water source options, (3) reduced analytical testing for produced water management, and (4) rapid onset of friction reduction without need for external surfactants. The DPFR provided efficiency improvements to the service company through fewer chemicals required to achieve high pumping rates. The operator benefitted from having greater flexibility in use of produced, recovered and recycled waters. Laboratory flow loop tests indicated that the DPFR would be an effective friction reducer for a wide variety of water types, and this was confirmed by field testing as shown in the treatment plots included in this paper. Minor modifications in material handling procedures were required in the application of the DPFR. This paper details the collaboration between a chemical manufacturer, a service company and an operator which resulted in the successful development, testing and deployment of an innovative technology in the Marcellus Shale. The DPFR technology offers environmental, economic, and operational advantages over the previous inverse-emulsion polymer technology.

In deepwater completions in the GOM, synthetic-based mud (SBM) has been widely used for drilling the reservoir section. With increasing well depth and higher reservoir pressure, higher-density drilling fluids are used more and more often. It has been observed that with increasing density of drilling fluid, the incompatibility between drilling fluid, completion fluid, and other well-treatment fluids can cause more problems to drilling and completions. Consequently, the incompatibility can reduce the effectiveness of well completions and result in lower production. Often, the formation damage caused by the incompatibility can be very difficult to remediate. We have identified incompatibility between drilling fluid, completion fluid, and other-well treatment fluids for many GOM wells in lab studies. Chemical additives were studied for preventing the incompatibility between drilling fluid, completion fluid, and other well-treatment fluids. Chemical additives selected from lab study have been applied to many GOM wells, and their use has resulted in improved well production and has prevented catastrophic damage to the wells. We developed proper lab test protocol to subjectively evaluate chemical additives that can prevent or minimize incompatibility between drilling fluid, completion fluid, and other well-treatment fluids. The application of the selected chemical additives on several GOM wells will be discussed. This paper will summarize the lab test methods and lab test results based on testing for several GOM wells. It will also summarize the end results of well performance with the application of these chemicals.

Completing deepwater Gulf of Mexico (GOM) wells with depths greater than 20,000 ft and high geopressure may require the use of higher-density fracturing fluids to reduce high wellhead treating pressures. In Shell's Deimos field, frac fluid density of up to 12.5 ppg was required. Although the industry has pumped 11.5 ppg NaBr-based borate cross-linked fracturing fluids, a 12.5 ppg NaBr-based borate cross-linked fracturing fluid has not been used until now. There are many challenges when applying a 12.5 ppg NaBr-based borate cross-linked fracturing fluid. The 12.5 ppg NaBr high-density, brine-based fluid has significantly different rheological behaviors than typical fracturing fluids made with freshwater or low salt concentrations. The high-density, borate cross-linked fluid responds very differently to shear history and recovers much more slowly than does freshwater-based fluid. Breaker efficiency is also very different. The highdensity, brine-based fracturing fluid is potentially incompatible with formation crude. Base brine quality was also critical to final fluid quality and quality control procedures had to be better defined. Shell developed lab and field QA/QC protocols to ensure the fluid met the frac & pack job requirements. With rigorous fluid testing and optimizations, three wells in the Deimos field were successfully completed in 2007. This paper summarizes the extensive rheology, fluid compatibility, fluid optimization, and fluid QA/QC processes. It also summarizes important aspects in the application of 12.5 ppg NaBr-based fracturing fluids. This paper will also discuss friction pressure, treatment pressure, actual frac & pack job performance, and postjob production data. The fracturing fluid design and test methodology applied in these three Deimos wells are also very beneficial to design and optimization of other kinds of fracturing applications. Introduction Deimos is a subsalt field located principally in Mississippi Canyon Blocks 806/807/762 in the Gulf of Mexico in 3,000 ft of water, approximately 1 mile west of the Mars TLP. Deimos is located predominantly on the Mars operating unit (Shell 71.5%, BP 28.5%) as shown in Figure 1. The bottomhole static temperature (BHST) ranges from 205°F to 220°F at perforation depths from about 22,000 ft to 26,000 ft MD. The pore pressure is greater than 16,000 psi, and the frac gradient was estimated to be greater than 0.88 psi/ft. The high pore pressure and long MD presented a challenge to pumping traditional frac & pack fluids. For a traditional frac fluid used in the GOM made of 3–7% KCl- or NaCl-based borate cross-linked fluid, the frictional pressure resulting from the long work string and the high pore pressure could result in high surface treating pressure exceeding the 15,000 psi pressure ratings of surface treating equipment and some wellhead components. In addition, high surface treating pressure may also cause the collapse of the bottomhole assembly (BHA).