Principal stresses, that is vertical, maximum horizontal and minimum horizontal stresses, and elastic moduli related to rock brittleness, like Young's modulus and Poisson's ratio, can be estimated from wide-angle, wide-azimuth seismic data. This is established using a small 3D seismic survey over the Colorado shale gas play of Alberta, Canada. It is shown that this information can be used to optimize the placement and direction of horizontal wells and hydraulic fracture stimulations.
Summary It is shown that the electrical breakdown induced during electrical stability (ES) tests of oil-based muds involves formation of a conductive bridge in the mud between the electrodes. Observations with an optical microscope demonstrate that this bridge is composed of aqueous fluid and particulate solids. Water is the key component, whereas particulate solids. Water is the key component, whereas the solids appear to be involved only as carriers of the water. Hematite is an exception since it, like water, can serve as a conductor. The absence of visible chemical changes during ES tests supports the contention that the rapid rise in the current is a conduction phenomenon, rather than true dielectric breakdown of the base oil. The ES voltage, the voltage at which the current rises abruptly, was found to be a function of the viscosity and the types and concentrations of solids, aqueous fluid and emulsifiers (surfactants). These trends are qualitatively consistent with a theoretical expression for breakdown of particulate-contaminated dielectric fluids, which suggests particulate-contaminated dielectric fluids, which suggests that the ES of a mud is a measure of its emulsion stability but not necessarily its oil wetness or oil-wetting tendency. Trends in ES are also consistent in most cases with other field indicators of emulsion stability, such as high-temperature high pressure fluid loss. Anomalies in ES trends are explained in terms of a physicochemical model for electrical breakdown. A field test based on the effect of incremental additions of barite was developed that serves to indicate the need for additional emulsifier, regardless of the type of weighting agent in the mud. A similar test is proposed that utilizes incremental additions of emulsifier. When coupled with the barite test, the emulsifier test can help to define the oil-wetting tendency of the mud, as well as its emulsion stability. Introduction Invert oil-based muds are water-in-oil (W/0) emulsions which typically contain an organophilic clay (OPC) and a weighting material, e.g., barite or hematite. The water phase is usually a solution of a salt (CaC12 is the most common) whose concentration is adjusted to match the water activity of the formation; this minimizes transfer of water to or from the water-sensitive zones and maintains a stable wellbore." The W/O emulsion itself is usually stabilized with a "primary emulsifier" (often a fatty acid salt), while the weighting material, along with drill solids which the mud acquires in use, is made oil-wet and dispersed in the mud with a "secondary emulsifier" (typically a strong wetting agent, such as a polyamide 2). Electrical stability (ES) of an oil-based mud is considered a measure of its emulsion stability. In the laboratory, a mud with a high degree of emulsion stability is generally smooth, shiny and does not adhere to the stirring spindle of a mixer. By contrast, a mud with a low degree of emulsion stability is dull, grainy and shows a marked tendency to adhere to the spindle. The oil wetness or oilwetting tendency of an invert emulsion mud is defined here as the ability of the mud to incorporate foreign materials into the external, or oil, phase. A mud with high emulsion stability is phase. A mud with high emulsion stability is oilwet, by definition, but may not necessarily be oilwetting. In his patent application for the first ES meter, Crittendon hypothesized that ES is related to the stability of W/O emulsions and that higher ES voltages correspond to more stable, or "tighter", emulsions. This result was extrapolated to invert emulsion drilling fluids, which are more complex by virtue of their solids content. Thus, a mud with a high ES voltage was considered to be stable.
Summary Mud systems with partially hydrolyzed polyacrylamide polymer (PHPA) are used worldwide and have proved effective and polymer (PHPA) are used worldwide and have proved effective and versatile for inhibiting troublesome shale formations. We made significant changes in the generally recommended compositions for these systems and developed a systematic approach to applying them. The most significant changes are (1) the constant maintenance of 1.0 lbm/bbl [2.9 kg/m3] PHPA (active) on the basis of materials balance and the supplemental addition of PHPA to account for its loss and degradation, (2) tightly controlled fluid loss, and (3) selective use of seawater and NaCl for inhibition. Introduction The well-known advantages of low-solids polymer muds include faster rates of penetration (ROP's), fewer bits, and shale inhibition resulting from low pH and adsorption of the polymer in cuttings and in the borehole. Milestones in this field include the development of low-solids polymer-extended muds, xanthan gum, and PHPA muds. The largest historical application of these muds has been in areas where the drilling rate is slow and some shale inhibition is required, such as the Rocky Mountains of western Canada and the North American midcontinent area. The application of polymer muds has been hindered by two criticisms. First, they are difficult to run because mud-engineering maintenance guidelines are very different from conventional bentonite mud systems. Second, they are less solids-tolerant than dispersed or lime-based systems. Consequently, these muds often have proved uneconomical for drilling geologically young and highly dispersive shales or for drilling with high mud weights (greater than 14 lbm/gal [greater than 1700 kg/m3]). However, as use of these systems continued, engineering practices evolved to where, in recent years, these systems have been practices evolved to where, in recent years, these systems have been used very successfully in young dispersive shales and in higher mud weight ranges. Recent success of the PHPA mud system is attributed to improved mud-engineering guidelines and solids-control practices. Although more is known from field applications about how practices. Although more is known from field applications about how the products work and the systems behave, the technology of PHPA mud systems is still developing. We currently use PHPA mud systems worldwide. This paper summarizes recent experiences and details field-developed guidelines for running PHPA muds. Comparison of Polymer Muds With Clay Muds Drilling of oil and gas wells always results in the incorporation of native clays into the mud system. About 60% of the world sedimentary volume consists of shales (formations with a high clay content produced by compaction and dewatering of fine-particle-size sediments). As we drill through shales and the mud carries low-gravity drill solids out of the borehole, shale particles too small to be removed by the solids-control equipment particles too small to be removed by the solids-control equipment accumulate in the mud, increasing the mud's clay content. It is instructive to compare how the viscosities of conventional clay and polymer-based muds are controlled by mud products added to handle the buildup of clay solids during drilling. The viscosity and gel strength characteristics of bentonite muds are achieved by clay-particle-to-clay-particle interactions. Clay particles in the water phase are attracted to each other and build up a structure that produces viscosity. The commonly used thinners are small, negatively charged molecules (small relative to high-molecular-weight viscosifying polymers) that adsorb on clay particles to increase surface charge, which reduces attractions particles to increase surface charge, which reduces attractions between particles. This is called electrostatic stabilization. High pH is an important feature of these dispersed systems. The high hydroxideion concentration activates the common thinners (makes them more negative) but also leads to greater dispersion (clay cleavage) of both drill cuttings and the wellbore by increasing the negative charge on the clay surfaces.
Many well stimulation designs in the Bakken Petroleum system of the Williston Basin include hybrid treatments in which multiple fluid types and proppant types are incorporated into the pumping schedule. The industry at the present time is generally focused on cost competitiveness and efficiency. Given the changing trend, a convergence of well stimulation techniques might be expected, however stimulation design and strategies among operators have diverged (figure 1) relative to fluid choices, proppant, and pump rates [Robart et al 2013]. This paper presents an investigation that was conducted to ascertain the potential effect of the mixed proppant sizes relative to fracture conductivity. It is common in hybrid completion designs to mix various sizes of proppant based on stimulation design assumptions and criteria. It is expected that a high concentration of the least conductive proppant is likely to dominate the overall fracture conductivity, but to what degree and to what extent was the question. Also, proppant size distribution is likely to vary throughout the fracture. Depending on the treatment fluids, viscosity, and expected settling rates, proppant may be segregated by tail-in, evenly blended, or blended with dominant concentrations of one particular size. These potential scenarios were simulated in conductivity cell experiments to gain an understanding from laboratory results. The results include a number of interesting conclusions regarding the selection of tail-in proppants and the performance relative to smaller sizes of sand and light weight ceramic.
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