A successful acid fracturing design depends strongly on the rock-acid reactivity. In carbonate reservoirs where the reaction is mass transfer limited, flow rate and diffusion coefficient determine the overall reaction rate. In an acid fracturing program, the value of the acid diffusivity is often unknown to the engineers. Quantifying diffusivity is a key step for a successful acid fracturing design. Diffusion coefficients of straight acids, gelled acids, and emulsified hydrochloric acids were measured with both the diaphragm cell and the rotating disk device. In addition, the data obtained has been utilized to develop a new correlation to predict the diffusivity coefficient of hydrochloric acid, which accounts for the effect of temperature, acid concentration, and rock type with which the acid reacts.

SPE Member Abstract The presented work is a compilation of efforts directed by 20 producing companies, service companies and suppliers to understand the effects of environmental conditions and fracturing fluids upon various classes of propping agents. In preliminary work the long-term effects of closure and temperature combinations ranging from 3000 psi and 150 degrees F to 10,000 psi and 300 degrees F are investigated on sands, resin coated sands and ceramic proppants between monel shims and medium-hard sandstone. This portion of the work sets the baseline for equilibrium permeabilities and conductivities taking into account time, closure stress, temperature and embedment. The work then focuses on the effects of common crosslinked fracturing fluids and fluid loss additives upon conductivity and permeability. Equipment is described and procedures are established using a fracturing treatment simulator that permits job-like fluid mixing, tubing shear history (1000–1500/sec), formation shear (40-50/sec), heat-up, dynamic fluid leakoff through formation core at 1000 psi to create filter cakes, and the placement of proppant. Leakoff rates during and after the treatment, and conductivities and permeabilities measured after cleanup, reveal relationships of additives and conditions that will be useful in the design of fracturing treatments and the prediction of well performance. Introduction Today's design engineers have sophisticated programs at their fingertips to estimate fracture geometry and post-treatment production. The programs, however, often predict fracture flow capacities and productivity increases that are as much as an order of magnitude higher than actual results. This discrepancy cannot be attributed to a single input error but rather a combination of input parameters and/or calculations, including fluid rheology and leakoff that impact on the geometry, and finally, conductivity and permeability of the proppant pack. Much of the error results from applying laboratory data such as static leakoff data and conventional short-term conductivity data in the design program. The design engineer realizing that factors such as filter cake deposition, embedment and time at temperature can dramatically influence conductivity and permeability, applies a fudge factor of from 0.5 to 0.1 to short-term laboratory proppant conductivity data and/or to be safe may multiply the fluid loss coefficient by a factor of 2(3). The majority of proppant conductivity data used to design fracturing treatments has been based on ambient temperature conditions, line with current API testing procedures. As early as 1973 Cooke published data that recognized the effects of hot brine and turbulence. Recent work has looked at long-term effects of moderate temperature and high temperature upon the conductivity of proppants. Although subsequent investigators have recognized the need for this type of data, the generation of consistent long-term data has been hampered by problems such as proppant dissolution and oxidation products that plug the pack. Recent evaluations that have instituted oxygen removal and silica preconditioning systems have created a consistent set of baseline data that begins to show the effects of time and temperature upon the conductivity of proppants. This has set the stage to evaluate the effects of embedment and fracturing fluids upon conductivity. P. 229^

Slickwater fracturing has increased over the past decade with the advent of shale gas plays. Horizontal wells are now the standard with up to 1 million gallons of water in as many as 6 to 9 frac stages per well. The objective is to create as much contact with the reservoir as possible and many times a secondary goal is to prop open the created fractures. Additive packages have been minimized to save money. Due to environmental concerns and fresh water availability, the flowback and produced water is collected and used for subsequent fracture treatments. The purpose of this work is to examine water treatment techniques and critically evaluate the performance of additives that are employed in slickwater fracs of shale reservoirs and give guidelines for selecting additives that will optimize performance during pumping, fluid recovery and production. Comments will be made on the topic of proppant selection. Following the proppant, the major additive in most jobs will be the friction reducer which is required to reduce the friction pressure while pumping at the extreme rates of 50 to 120 barrels per minute (bpm). The second concern should be additives to treat bacteriological activity. The injection of water will ultimately result in the cultivation of sulfate reducing bacteria which produce Hydrogen sulfide (H2S) and biproducts such as black iron sulfide on the surface if not treated properly. Scale inhibitors become vitally important as water dissolves salts from the formation. Shales have sub microDarcy matrix permeability with natural fractures and cleats providing avenues for gas desorption and flow to the wellbore. Shales can have as much as 50% clays. Are additives necessary to stabilize clays? Finally, the use of surfactants can be beneficial in promoting the flowback of injected fluids to restore the relative permeability to gas. Which surfactant types are the most beneficial? Introduction Revitalization of slickwater fracs over the last decade have increased due to higher natural gas prices and more experience in fracturing with lower cost fluids. Slickwater fracs have been employed in low permeability and large net pays, and require large amounts of water to obtain adequate fracture half-lengths. Before Barnett Shale was fractured in 1997, many fracs were carried out with a cross-linked fluid and large amounts of proppants. The difficulty in cleaning the wells and the low return made many wells uneconomical. Some wells were even treated with slickwater and no proppant. Initial production was higher but declined rapidly. Eventually, the state of the art has evolved to high rate slickwater fracs with various additives. The question to be addressed is how do the various additves perform in shale and how do we select which additves are necessary particularly in light of the fact that most fracs are now conducted with produced and/or flowback water from previous fracs. Selecting a method of extracting the gas is crucial in how one should stimulate the shale pay. The mechanical properties indicate that horizontal wells may be a viable option. Whether vertical or sub-vertical wells are drilled, there will be a variety of stimulation options available, with the selection of the fluid and additives being based upon the mineralogy. Fluid additive selection needs to take into account the:Tubulars and pumping rate and pressuresHigh percent of clays.Potential generation of fines both siliceous and organicAcid solubilityMicrobiological activityPotential for scale generationProblem with recovering injected fluids

Summary Back production of proppant from hydraulically fractured wells, particularly those completed in the northern European Rotliegend formation, is a major operational problem, necessitating costly and manpower-intensive surface-handling procedures. Further, the development of unmanned platform operations offshore, required in today's economic climate, is impossible as long as this problem remains unsolved. The most cost-effective potential solution to this problem is provided by curable resin-coated proppant (RCP), which consolidates in the fracture. Early field trials with RCP's, however, were not completely effective in stopping the back production of proppant. Typically, some 10% of the total volume of RCP placed in the fracture was backproduced. Two types of RCP back production were identified: during well cleanup (Type A) and after a long period of proppant-free production (Type B). Type A is believed to be caused by an insufficient strength buildup of the RCP pack. The influence of factors affecting RCP pack strength buildup-resin type, reservoir (curing) temperature, resin/fracturing-fluid interaction (under shear and temperature), and erosion of the resin from the proppant grains, which can reduce the RCP pack strength-have been studied in the laboratory. Type B proppant back production was suspected to be caused by a previously unobserved phenomenon: damage resulting from stress cycling that the proppant pack undergoes each time the well is shut in and put back on production. Further, the applied stress increases as the drawdown is increased and the formation is depleted. We performed a laboratory study to help clarify the effect of curing temperature, water production rate, proppant size, and stress cycling on the integrity of RCP packs. The experiments confirmed the field experience that stress cycling has a dramatic effect on proppant back production of commercial RCP packs. The number of applied stress cycles (i.e., the number of times the well is shut in) and the initial RCP pack strength appear to be the dominant factors that govern proppant back production. Dedicated experiments are therefore required to evaluate the use of RCP's to eliminate proppant back production for a particular field application. Introduction Sand production is an operational problem that has plagued oil and gas wells producing from clastic formations since the early days of the oil industry. By contrast, proppant back production is found only in wells where hydraulically created fractures have been packed with (large) volumes of proppant. The proppant pack is unrestrained at the fracture mouth; once proppant grains enter the wellbore, they can be brought to surface with the well fluids. Such back production of proppant from hydraulically fractured wells, particularly those completed in the northern European Rotliegend formation, is a major operational problem. It necessitates costly and manpower-intensive surface-handling procedures (viz., the daily dumping of proppant) and on-site control of the chokes when beaning up the wells. Further, erosion of well and surface facilities presents a safety hazard, and proppant remaining in the wellbore can shut off production by covering the productive interval. Consequently, the development of unmanned platform operations offshore, required in today's economic climate, is impossible as long as significant proppant back production occurs. Incidentally, a similar tendency for hydraulically fractured wells to backproduce proppant is observed in Alaskan operations; however, owing to the different conditions (onshore oil production), the approach adopted there is "to live with it."

Supercritical carbon dioxide (CO2) flooding is a widely used method in tertiary oil recovery; however, there are many challenges such as inefficient gas utilization, poor sweep efficiency and low oil recovery due to viscous fingering and gravity segregation. One recent development is the application of CO2 foam in order to reduce the CO2 mobility, especially in high permeability zones of the reservoir. However, the efficiency of the CO2 foam often decreases sharply during flooding as a result of contact with crude, adsorption of surfactants, high salinity in formation water and high reservoir temperature. Surfactant formulations which have better tolerance to these factors can greatly enhance the CO2 utilization, reduce the cost of surfactant, and improve the oil recovery. A series of formulations, including various surfactants and corresponding micro-emulsions, were evaluated as CO2 foaming agents in lab-based heterogeneous sandstone equipment at reservoir temperatures and pressures. This paper describes formulating high temperature CO2 foaming agent with co-surfactants and in a micro-emulsion system to improve crude, salt and temperature tolerance and minimize adsorption in order to place the foamer further into the formation.