No abstract

Crystallinity and melting behavior are directly affected by the presence of a noncrystallizable comonomer. Hydrogenated polybutadiene, HPB, emulates a random ethylene−butene copolymer and provides the basis for comparison to the equilibrium theory of Flory. Melting behavior, density (crystallinity), and SAXS long period were measured for HPB's having 12 to 88 ethyl branches per 1000 backbone C atoms. DSC curves calculated from equilibrium theory are compared to experimental traces. It is shown that the equilibrium melting temperature T m c of infinitely thick crystals, while thermodynamically correct, is inaccessible to experiment. Thickest crystals with observable populations melt at the practical final melting temperature T m f, which is below T m c. The peak melting temperature T m p has no relation to the most populous crystal thickness. Crystallization of molten copolymer chains leads to fewer thick and thin crystals than predicted by theory; the difference is attributed to kinetic factors of secondary nucleation barriers and mass transport. Crystallization at feasible rates is achieved when the melt is at a temperature low enough to undercool a sizable fraction of crystallizable segments. Crystallization prevents the motion of segments required to achieve equilibrium, so solidification proceeds as if the system were quenched, accounting for insensitivity of copolymer morphology to cooling rate. Only the size of the largest crystals which melt at experimental T m f can be established by thermodynamics. There is some evidence that small equilibrium crystallinities are approached in highly branched copolymers.

A combination of 13C and magnetic resonance experiments has been performed on a model ethylene copolymer (hydrogenated polybutadiene) of about 100000 molecular weight and 17 ethyl branches per 1000 total carbons. The fraction of ethyl branches found in the crystal in this 41 % crystalline sample was 0.06 ± 0.02, and the ratio of concentrations between the crystalline and noncrystalline regions was correspondingly about 1:10. For reasons of best integrability, the methyl resonance of the ethyl branches was used to deduce the concentrations in each morphological phase. This same resonance is rather ill-behaved in cross-polarization experiments, so several auxiliary experiments were undertaken to deduce the true concentrations attributed to each phase. The experimental technique utilizes cross-polarization as a probe of proton polarization levels; moreover, the success of the method relies on local proton spin diffusion. Results are discussed in terms of other experimental findings regarding the question of partitioning. Also, these results are used to interpret more accurately the data in a previous report on partitioning in an ethylene-l-butene copolymer having a branch concentration about 7 times smaller. Finally, in an appendix, some supplemental data are presented on the effects of magic-angle spinning on the spin dynamics of the noncrystalline region and the influence of this spinning on the validity of the results deduced from cross-polarization experiments.

The lattice parameters of a series of hydrogenated polybutadiene (HPB) model copolymers is measured as a function of branch content between 0 and 73 ethyl branches per 1000 C atoms. Expansion of the a and b axes nearly ceases for branch contents greater than 20 per 1000 C atoms. The c axis is seen to contract by a small amount with increased branching. The major cause of lattice expansion is limitation of crystal thickness by exclusion of branch points from the lamellar crystals coupled with surface stress on thin lamellae. A small fraction of ethyl branches are incorporated in the crystal; these expand the lattice by an additional amount.

Summary Back production of proppant from hydraulically fractured wells continues to create operational problems for oil and gas producers. As much as 20% of the proppant placed in the fracture can be returned to the surface, necessitating costly and labor-intensive surface-handling procedures. The development of unmanned platform operations remains impossible in some areas because of proppant back production. Flexibility in well turnaround and production strategies also can be very limited. Curable resin-coated proppant (RCP) has provided the most cost-effective and widely used method to control proppant back production. While this is a valuable technique that has served the industry well for many years, it is not universally successful. A new technology has been developed to control proppant back production and to increase flexibility in well turnaround and production strategies. The technology has been used successfully on several hundred hydraulic fracturing treatments. In this technology, a mixture of fibers and proppant is pumped into the fracture to form a pack that is resistant to proppant back production under typical oil/gas production conditions. The proppant/fiber mixture depends on a physical mechanism rather than chemical bonding to increase pack resistance to flowback. There are no minimum closure stress, temperature, or shut-in time requirements associated with the use of this technology, which increases the flexibility available to the operator to optimize well turnaround and production strategy. This paper reviews the laboratory data relevant to the understanding and application of this technology. Studies include proppant pack resistance to flowback in one- and two-phase flow, the effect of cyclic loading, aging phenomena, permeability/conductivity studies, and fluid/breaker interactions. The benefits of the technology are illustrated with field studies. Introduction Proppant back production has been of concern in hydraulic fracturing for more than 20 years. It has received increased attention in recent years as larger fracture widths and the use of higher proppant concentrations have become more prominent. Back production usually is observed when the well is turned around after the hydraulic fracturing treatment. Back production may stop in time, be controlled by limiting the production rate from the well, or continue through the economic life of the well. Back production from hydraulically fractured wells presents operational problems. It often necessitates costly and labor-intensive surface-handling procedures and on-site control of chokes when beaning up the wells. The erosion of well and surface facilities presents a safety hazard. Proppant remaining in the wellbore can shut off production by covering the productive interval. The magnitude of the problem and the range of viable approaches vary from location to location. As much as 20% of the proppant placed in the fracture has been returned to the surface in Alaska, and as much as 10% is not uncommon in the North Sea.7 Back production can yield as much as 100,000 lbm of proppant. In Alaska, many operators "live with" the problem. In the North Sea, the development of offshore, unmanned platforms is often impossible. Continuous proppant production can sometimes be stopped by producing wells on a restricted choke. In some cases, changes in job design (proppant type, proppant size, final concentration of proppant in slurry, final pumping pressure, forced fracture closure, or lengthened fracture shut-in period) can be effective in reducing or eliminating proppant flowback. The most economical and widely used proppant-flowback-control technique is the curable RCP, which has been the single most effective technology available. Sales of curable RCPs exceed 60,000,000 lbm/yr (and could be significantly higher than that). While curable RCP's have had a great deal of success, they are not, nor could they be expected to be, universally applicable. A new technology has been developed to prevent proppant back production and to allow more flexibility in flowback design and production strategy. The technology relies on a physical mechanism - fiber reinforcement - to increase the resistance of the pack to flowback during production of oil or gas. This report presents laboratory data and field examples of the advantages of this new technology. Its limitations are also presented.

As mature fields produce larger quantities of water, operators and service companies find themselves challenged with disposing flowback and produced water to reduce costs, handling the logistics of getting enough water to hydraulically fracture the well, as well as complying with stricter governmental regulations. As produced water is recycled and used in fracturing applications, each cycle of re-used water returns with a more complex chemical make up than before. Therefore, the usable lifetime of the recycled water is shortened or requires expensive cleaning or dilution with fresh water to make it a viable solvent base for fracturing fluids. This paper describes the process to properly design fracturing fluids using flowback and produced water. The importance of flowback water analysis is highlighted for optimizing fluid performance downhole. Recent developments in proper selection of fluid additives and viscosifiers for slickwater and crosslinked fluids are discussed. We will describe in detail how the salinity, biological activity, and scaling tendency of these waters can impact fluid performance. Other factors, including organics and suspended solids will be included in the discussion. Laboratory examples will be shown to demonstrate the importance of following a systematic approach. Ultimately, this paper focuses on how to optimize well performance using recycled waters in stimulation applications. Introduction The exploration and production (E&P) industry in the United States generates approximately 210 bbls/day in produced water (Arnold et al., 2004). Other reports suggest that for every barrel of oil produced in the United States, 10 barrels (bbl) of produced water is generated (Khatib and Verbeek, 2002). Even though some of this material can be managed at the well site, many operators in the United States seek offsite management options for their waste. Offsite disposal companies must comply with state and federal laws including the Resource Conservation and Recovery Act (RCRA), the Environmental Protection Agency (EPA), the Clean Water Act (CWA), and the Safe Drinking Water Act. For instance, to discharge into surface water in Pennsylvania and Wyoming, the company must do so under a National Pollutant Discharge Elimination System (NPDES) permit or into a publicly owned treatment work (POTW). Typical costs associated with disposal range from $0.30 to $10/bbl for injection or cavern disposal to $15 to $22/bbl for solidification and burial in a landfill (Puder, 2007). Operators in the United States have reported that disposal and treatment costs for their produced water exceeded $400 MM/yr (Khatib and Verbeek, 2002). Finding alternative uses for flowback water in the E&P industry is both an economic as well as an environmental issue. In an effort to circumvent some of the extra costs, operators have reported the use of recycled produced waters in reservoir management processes (Khatib and Verbeek, 2002). Water treatment options have been discussed that include desalination, reverse osmosis, and 'floc 'n drop' methods but trucking costs associated with moving water to treatment facilities often make this an expensive option for operators (Kaufman et al., 2008, Horn, 2009). Literature has also been documented on the use of untreated recycled waters in high rate, low permeability shale reservoirs (Arthur et al., 2009). Water volumes for a typical slickwater hydraulic fracture treatment can average 715 m3 (6,000 bbl) per stage with 6 to 10 stages per horizontal well. Large treatment volumes for these applications offer a unique opportunity for cost savings if flowback water can be used in place of other fresh water sources. This approach saves on logistical problems as the water source is near the next treatment site.

Summary Flowback aids are usually surfactants or cosolvents added to stimulation treatments to reduce capillary pressure and water blocks. As the stimulated gas reservoirs become tighter, the perceived value of these additives has grown. This value must be balanced with the cost of the additives, which can be significant in slickwater fracturing treatments. There is a range of different flowback additives containing water-wetting nonionic to amphoteric, microemulsion (ME), and oil-wetting components. Determining the best additive for a specific reservoir is not a simple matter for the end user, and the existing literature is full of conflicting claims as to which one is most appropriate. This paper compares four different flowback aids: ME, two waterwetting flowback additives, and an oil-wetting additive. Careful laboratory testing was conducted to evaluate surface tension and contact angle for each flowback aid, using the recommended concentrations. Imbibition and drainage tests were performed that allowed calculation of the capillary pressures for the three additives. Drainage tests were performed on 1- to 3-md and 0.1-md cores. Capillary-tube-rise testing was also conducted as a check of the coreflood testing capillary pressures. This provided several different methods to determine capillary forces for the flowback aids. In addition, fluid-loss testing was conducted to determine if the flowback additives could improve fluid loss. All the flowback aids demonstrated low surface tension (approximately 30 mN/m), but each was different in terms of surface wettability and adsorption in the rock. In all cases, the flowback aids reduced capillary pressure to similar levels 70% lower than water alone. One of the water-wetting additives had much stronger adsorption in the core material than the other additives. The ME and the oil-wetting additive had improved fluid loss in a fully formulated fracturing fluid. In spite of the low capillary pressures, the additives had little effect on cleanup or return permeability on cores greater than 1 md. There are several implications of these results for the operator. Different flowback additives have a tradeoff of properties, and depending on the reservoir, selecting one that leaves the formation with certain wettability may be advantageous. Our testing indicated that understanding the reservoir is important in selecting the appropriate flowback aid.

Open-hole horizontal wells are increasingly used to improve reservoir exploitation and production rates by targeting specific zones and maximizing reservoir exposure. The drilling fluid of choice in many of these wells is "oil based" due to enhanced drilling rates with minimized friction as well as improved wellbore stability. However, in horizontal wells requiring gravel packs, the industry in general has been reluctant to use OB reservoir drilling fluids (RDF) for various reasons. Because the gravel pack (GP) carrier fluids that have been successfully used to date are all water-based and the use of OB-RDF would necessitate displacement of open hole to WB fluids prior to GP, the practice has been to switch to WB-RDF once in the reservoir section. This was due to concerns as to adverse fluid-fluid interactions resulting in sludging and difficulty in maintaining filtercake integrity while displacing OB-RDF in the open hole, leading to complex fluid management issues. An additional factor has been the perception that WB-RDF filtercakes are easier to remove should it be necessary, since most commonly used cleanup chemicals are water-based and the weighting/bridging agents used in the RDF are also water-wet if the RDF is water-based. In this paper, we present results from experiments conducted with OB-RDFs in the presence of gravel packs. We investigate two scenarios:the gravel pack carrier fluid is water-based, andthe gravel-pack carrier fluid is oil-based. In the first case, provided that no sludges are formed during displacement to water-based fluids, the retained permeabilities are comparable to or better than those obtained with WB-RDFs, although values lower than 0.04% can be expected in the presence of sludging. Another issue relevant to gravel packing wells drilled with OB-RDFs is the yield strength of their filtercakes in comparison to WB-RDFs. It is found through yield stress measurements of various RDF cakes that OB-RDFs have several orders of magnitude lower yield strength than their WB counterparts. This finding is consistent with the reported lower flow initiation pressures for OB-RDFs, and indicates that cake erosion during gravel packing is more likely with OB-RDFs. In order to optimize the sequence of fluids to obtain a good displacement of the RDF at field scale, we use a purpose-built numerical simulator. This simulator is a fluids mechanics code that can accurately calculate displacement fronts in field conditions: eccentric deviated annulus with as many fluids as necessary. Its main use is to detect unstable displacements such as channeling of the displacing fluid on the wide side of the annulus or slumping in horizontal portions. Furthermore, we provide data on a new oil-based gravel pack carrier fluid that can be used to eliminate fluid incompatibility and fluid management issues associated with the switch from OB to WB fluids. The laboratory and large-scale yard test results are presented, addressing critical considerations for oil-based GP carrier fluids. It is found that such emulsion systems can thicken or break (depending on the emulsifier concentration) at high shear rates unless the emulsion is made at the highest shear that it will be exposed to. The implications of these results on field practices are discussed along with recommendations on avoiding damage in gravel packed wells drilled with oil-based RDFs.