Atomic force microscopy (AFM) is used to image hydroxypropylguar gel structures formed under quiescent conditions as well as gels formed under varying levels of steady shear. Hydroxypropylguar (HPG) in aqueous solution is representative of a high molecular weight, flexible polysaccharide. HPG readily cross-links with borate ions to form a gel network. The steady-state rheological properties of borate cross-linked HPG gels are shown to be dependent on the shear rate applied during the gelation reaction. The storage modulus is used as an indication of the gel strength. The gel strength is shown to be enhanced under moderate shear conditions and is seen to decrease under high shear during gelation. AFM images show an aligned, ordered structure is present in the high gel strength material (low preshear rate), with a random network structure present in the gel formed under quiescent conditions. A material composed of globular structures is apparent in the gel formed under high shear. The variation in the observed microstructure and rheological data with preshear rate is discussed in relation to alignment of polymer molecules in shear fields.
Summary The complex rheological behavior of crosslinked fracturing fluids is a function of shear history, temperature, and chemistry. Understanding the relationship between these variables and the downhole properties of the fracturing fluid is a challenging task. Rheological measurement techniques are presented that unravel some of the mystery associated with crosslinked fracturing fluids. The concept of a physical gel-point for fluids undergoing crosslinking is introduced and shown to correlate strongly with the proppant- carrying ability of the fluid. The gel-point variation with temperature and chemistry is discussed. This variation can be studied in the laboratory to provide an in-situ field performance evaluation without the need for expensive proppant-transport flow loops. The limitations for newly developed, low-concentration polymer fluids are also discussed. The fluid system chosen for analysis was the pH-activated, borate-crosslinked hydroxypropylguar (HPG) fluid. Introduction Crosslinked polymer fluids, in particular the borate-guar (or HPG) fluid, have been proven as highly successful fracturing fluids for many years.1 Recently, new generation, low-polymer fluids have proven to be effective fracturing fluids in low-temperature reservoirs.2 While these fluids have demonstrated field success, methods for understanding the crosslinking mechanism and the physical properties that lead to their success are still not complete. Rheological techniques that use oscillatory testing provide an ideal method for studying the liquid-to-gel transition that occurs in crosslinked fracturing fluids.3,4 Oscillatory rheometry allows the network structure of the gel to be studied in a nonintrusive manner. In this way, it is possible to monitor the effect that polymer concentration, crosslinker concentration, and temperature have on the development of the gel structure and, subsequently, evaluate the potential performance of specific fluids for use in the field. The gelation process of the borate-crosslinked HPG fluid is pH controlled. At low pH values, the fluid is a liquid, while at high pH values, the fluid is in the gel phase. The key components of the system are the HPG polymer and a borate source. In this instance, boric acid is used as the borate source. Controlling the pH of the system controls the concentration of borate ions in solution. The borate ion is essential for crosslinking to occur. A more detailed description of the HPG-borate chemistry is given by de Kruijf et al.5 Rheological data for steady-state fluid samples allow the approach to the gel point to be characterized as well as denoting the exact point of transition from the liquid phase to the gel phase. Once the fluid is in the gel state, it is able to suspend and transport proppant. Fluid Preparation A systematic approach to fluid preparation was used to avoid problems associated with sample variation. The required volume of water was heated to 140°F, at which point the HPG polymer was added gradually while applying high shear to the fluid. Once all the polymer was added, shearing was continued for 15 minutes. At this point, the sample was immersed in a water bath and held at 140°F for 1 hour. The sample was then placed on a bench-top roller to blend for 24 hours. A concentrated NaOH solution (20 wt% NaOH) was used to adjust the fluid pH. After each addition of NaOH, the sample was again heated to 140°F and rolled for an additional 24 hours. After loading a sample into the rheometer, a minimum of 15 minutes was allowed before testing to permit the crosslinks to reheal and reach equilibrium. In all fluid samples tested, the boric acid concentration was 3 lb/thousand gal (0.36 g/L). Rheological Data All rheological data were obtained with a Weissenberg controlled-strain rheogoniometer with a cone-and-plate test fixture. Steady-state fluid samples (with a constant pH) at varying stages of crosslinking were tested at strains that were within the linear viscoelastic response region. A detailed discussion of the testing procedure is given elsewhere.6 The key parameter for gel-point determination is tan d. Tan d represents the ratio of the loss modulus (G") to the storage modulus (G'). The storage modulus represents the elastic, or solid-like, behavior of a fluid, while the loss modulus represents the viscous, or liquid-like, behavior of a fluid. These properties are traditionally measured as a function of the oscillatory frequency. A detailed discussion of the storage modulus and loss modulus is given by Ferry.7 The tan d vs. the frequency data for fluids ranging from pH values of 6.25 to 11.29 are given in Fig. 1. The polymer concentration of the fluid given in Fig. 1 is 40 lb/thousand gal (0.48 wt%), with a boric acid concentration of 3 lb/thousand gal (0.36 g/L). The molecular weight of the HPG sample was estimated to be 3.5×106.6 For fluids in the liquid phase (low pH), the slope of tan d vs. the frequency curve is negative. As the pH is increased, the magnitude of the slope decreases and approaches zero. For fluids in the gel phase (high pH), the slope of the curve is positive. The exact pH corresponding to a zero gradient in tan d vs. the frequency is referred to as the gel point.3 Conceptually, the gel point represents the point at which all the polymer molecules in the solution are interconnected by at least one crosslink. The effective molecular weight of the polymer at this point approaches infinity. To accurately determine the gel point, a first-order linear regression is plotted through the data points for each individual fluid. In Fig. 2, the gradient of each regression curve is plotted as a function of pH. A clear distinction can then be made of the transition from liquid (negative gradient) to gel (positive gradient). Thus, this analysis technique provides a simple method for determining the gel point of a crosslinked polymer fluid. For the fluid system depicted in Fig. 2, the gel point corresponds to a pH of 8.7 at 71.6°F. Particle-Settling Data Simulating the proppant-transport conditions expected downhole in a fracture has traditionally required expensive procedures and equipment.8 For this reason, a simplified approach has been pursued. Single particle-settling experiments were performed with a glass bead falling through a cylinder that contained the fracturing fluid. Fig. 3 depicts the apparatus used to quantify the settling rate of a 5-mm-diameter glass bead in a 50-mm-diameter cylinder that contained the test fluid. The settling rate for steady-state fluids at varying degrees of crosslinking was measured and correlated with the measured rheological properties of the fluid. Fig. 4 presents the settling rate vs. the fluid pH, where the fluid pH is used as an indicator for the degree of crosslinking of the fluid.
Cuttings transport in highly deviated wellbores is more challenging and critical than in vertical wells. By optimizing drilling practices and sweep programs, on bottom drilling time can be increased and the need for wiper trips minimized. Data from two geological side tracks drilled from the same vertical wellbore are used to demonstrate the improved efficiencies possible when using weighted sweeps rather than high viscosity sweeps for hole cleaning in deviated wellbores. In the examples discussed in this paper, over $500,000 in savings were realized by the operator through using optimized drilling practices and engineered sweeps. Optimizing the use of rotation and circulation versus continuous sliding also can contribute to improved drilling efficiency. In addition, computer simulation data are presented to support the field observations. The use of sweep reports is an integral component of tracking sweep performance. Introduction Successful drilling of all wells requires efficient hole cleaning. When drilling deviated wells the challenge of maintaining efficient hole cleaning is typically greater than when drilling vertical wells. Some of the primary factors contributing to these greater challenges include drill pipe eccentric in the hole, the need for slide drilling (to build angle and maintain direction), and the resultant skewed flow distribution in the annulus1,2. The rheological characteristics of drilling fluids lead to a skewed flow distribution in the annulus for drill pipe that is eccentric in the hole. When drilling deviated and horizontal wells the drill pipe is usually located on the low side of the well bore, forcing the majority of the fluid to flow above the drill pipe. Annular velocity modeling of Herschel-Bulkley fluids clearly demonstrates this point. The shear thinning behavior of the fluid, combined with the yield stress characteristics of the fluid do not favor flow in the restriction below the drill pipe. Optimizing the rheology of the fluid to minimize this effect is an important part of well planning and design. It must be acknowledged that rheology modification alone cannot overcome the problem. A compounding factor associated with drill pipe being eccentric is the fact that drilled cuttings will settle towards the low side of the annulus due to gravity. Regardless of the drilling fluid rheology, it is almost impossible to clean a high angle wellbore without the action of drill pipe rotation3,4. Drill pipe rotation acts to agitate any settled solids back into the flow stream. A solids bed will develop over time in the absence of drill pipe rotation, which can impact on the annular equivalent circulating density (ECD), cause pack-offs and result in stuck pipe. Monitoring annular pressure just above the bit, together with accurate modeling and tracking of pick-up weight, slack-off weight, torque and drag can provide valuable insights into the development of a cuttings bed. This information should be utilized efficiently to detect the onset of solids build-up down hole before the situation becomes critical5.
Many of the technical challenges of drilling in deepwater have been well documented in the literature. One of the primary concerns is the narrow operating window between pore pressure and fracture gradient that often results in major fluid losses when drilling, running casing, and cementing. Deepwater fracture gradients are typically much lower than those encountered onshore or in shallow water (Fig. 1) thus preventing losses in deepwater can be more difficult. Failure to minimize lost circulation can greatly increase the already high cost of drilling, as well as risking loss of the well. Successful management of lost circulation in deepwater should incorporate identification of potential loss zones, optimization of drilling hydraulics, and clear, easy to follow procedures should lost circulation be encountered. The aim of this paper is to review the top 10 concerns associated with lost circulation in deepwater environments. This top 10 list addresses the causes of lost circulation and recommended solutions for managing these problems. Based on experience in various deepwater basins around the world, including the Gulf of Mexico, Brazil, and West Africa, the top 10 concerns aresub-salt rubble zones,locating loss zones,seepage losses,drilling, running casing and cementing with synthetic-based drilling fluid,drilling practices, excessive rate of penetration and hole conditions,wellbore breathing (ballooning),low temperature drilling fluid rheology,inadequate shoe tests,synthetic-based fluid compressibility, andwell control. 1. Sub-Salt Rubble Zones Drilling through salt formations can be troublesome for a number of reasons. Typically, the formations immediately below the salt are either mechanically weaker or fractured, introducing a greater risk for loss of returns. The thief zone immediately below the salt formation can be a thin zone of highly fractured rock, usually shale. The non-productive time treating severe sub-salt losses can be substantial, with obvious cost implications for deepwater drilling operations. Often on exploration wells little information regarding pore pressure and fracture gradient is available. Gulf of Mexico sub-salt wells often encounter higher pore pressures below the salt, creating challenging well control issues. In this instance the higher mud weights required to balance the pore pressure place even greater stress on the weakened sub-salt formations. Losses in the formations directly below the thick salt zones are typically severe, ranging from 16 m3/hr (100 bbl/hr) up to total loss of returns and the inability to maintain a full annulus. A wide variety of lost-circulation materials (LCM) have been applied in sub-salt thief zones, in an effort to control losses. Pills containing sized solids, gunk squeezes, conventional cement squeezes, and foamed cement have all been proposed as solutions to sub-salt lost circulation.1,2 Due to the extensive and deep network of fractures associated with rubble zones, filling the network of fractures has always been a challenge. One theory proposed that particulate materials and high compressive strength lost circulation pills (i.e., cement) were failing to reach the tip of the fractures, acting as a proppant and not allowing the fractures to heal. Consequently, the low fracture re-opening pressures allowed for continued losses.3 A recently developed Crosslinked Polymer Pill (CPP) was successfully employed for lost-circulation control in sub-salt sections in deepwater applications in the Gulf of Mexico. The CPP was a blend of crosslinking polymers and fibrous material. The crosslinking agents are activated by time and temperature, or by shearing at the bit. When set, the pill produces a substance described as rubbery, spongy and ductile. The setting time is fully controllable by using either a retarder or accelerator that is based upon the thief formation/bottomhole temperature.4,5,6 The CPP provides for rapid and effective sealing of sub-salt rubble zones that minimizes non-productive time. 2. Locating Loss Zones The types of tools and methods available for thief zone identification include:Real-time geomechanical analysis methodsPre-drill geological analysisPressure transducer surveys, Openhole logs, Hot wire surveys, Radioactive transducer surveys, Temperature surveys, and Spinner surveys
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