Long-term conductivity testing at realistic environmental conditions has greatly improved the measurement of proppant pack permeability. However, the use of low flow rates to insure Darcy flow in such measurements has masked the total effect of failed proppant fines on proppant pack permeability. As flow rates increase, corresponding with those commonly found in the field, fines are mobilized and migrate into new positions that reduce the permeability of the proppant pack beyond that normally observed in conductivity measurements. This effect has generally been overlooked in proppant pack design.This paper examines the extent of conductivity reduction caused by migrating proppant fines and the effect of proppant type on the extent of that reduction. The role of fines migration on the conductivity of proppant packs containing two different types of proppants, where the more capable proppant is used near the wellbore, is also evaluated.Representative commercially available proppants, including sand, resin-coated sand, and low density ceramics are included in the study.

A test apparatus is designed to carry out dynamic and static fluid-loss tests of fracturing fluids. This test apparatus simulates the pressure difference, temperature, rate of shear, duration of shear, and fluid-flow pattern expected under fracture conditions. For a typical crosslinked fracturing fluid, experimental results indicate that fluid loss values can be a function of temperature, pressure differential, rate of shear, and degree of non-Newtonian behavior of the fracturing fluid. A mathematical development demonstrates that the fracturing-fluid coefficient and filter-cake coefficient can be obtained only if the individual pressure drops can be measured during a typical fluid-loss test. Introduction In a hydraulic fracturing treatment, the development of fracture length and width is strongly dependent on a number of key fluid and formation parameters. One of the most important of these parameters is the rate at which the fracturing fluid leaks, off into the created fracture faces. This parameter, identified as fluid loss, also influences the time required for the fracture to heal after the stimulation treatment has been terminated. This in turn will influence the final distribution of proppant in the fracture and will dictate when the well can be reopened and the cleanup process started. Historically, tests to measure fluid loss have been carried out primarily under what is characterized as static conditions. In such tests, the fracturing fluid is forced through filter paper or through a thin core wafer under a pressure gradient, and the flow rate at the effluent side is determined. Of course, the use of filter paper cannot account for reservoir formation permeability and porosity; therefore, the fluid-loss characteristics derived from such tests should be viewed as only gross approximations. The static core-wafer test on the other hand, reflects to some extent the interaction of the formation and fracturing-fluid properties. However, one important fluid property is altogether ignored in such static core-wafer tests. This is the effect of shear rate in the fracture on the rheology (viscosity) of fracturing fluid and subsequent effects of viscosity on the fluid loss through the formation rock. In the past, several attempts were made to overcome the drawbacks of static core-wafer tests by adopting dynamic fluid-loss tests. Although these dynamic tests were a definite improvement over the static versions, each had drawbacks or limitations that could influence test results. In some of the studies, the shearing area was annular rather than planar as encountered in the fracture. In other cases, the fluid being tested did not experience a representative shear rate for a sufficiently long period of time. An additional problem arose because most studies were performed at moderate differential pressures and temperatures. The final drawback in several of the studies was that the fluid flow and leakoff patterns did not realistically simulate those occurring in the field. In the first part of this paper, we emphasize the design of a dynamic fluid-loss test apparatus that possesses none of these drawbacks. In the second part of the paper, test results with this apparatus are presented for three different fluid systems. These systems areglycerol, a non-wall-building Newtonian fluid,a polymer gel solution that is slightly wall-building and non-Newtonian, anda crosslinked fracturing system that is highly non-Newtonian in nature and possesses the ability to build a wall (filter cake) on the fracture face (see Table 1). The fluids were subjected to both static and dynamic test procedures. In the third part of the paper, results of experiments carried out with crosslinked fracturing fluid for different core lengths, pressure differences, temperatures, and shear rates are compared and the significance of the difference of fluid loss is emphasized. Experimental Equipment and Procedure The major components of the experimental apparatus shown in Fig. 1 are a fluid-loss cell, circulation pump, heat exchanger, system pressurization accumulators, and a fluid-loss recording device. The construction material throughout most of the system is 316 stainless steel. The fluid loss is measured through a cylindrical core sample, 1.5 in. [3.81 cm] in diameter, mounted in the fluid-loss cell. Heat-shrink tubing is fitted around the circumference of the core and a confining pressure is maintained to prevent channeling. Fracturing fluid is circulated through a rectangular channel across one end of the core. SPEJ P. 482^

An accurate determination of propped fracture geometry will help optimize the benefits derived from a hydraulic fracturing treatment. While advancements in determining propped fracture height have been made recently, there has been no new technology introduced addressing the other aspects of propped fracture geometry. A new tracer technology has been recently introduced and field tested. This technology incorporates a non-radioactive tag into the coating of a resin coated proppant. The tagged proppant is non-hazardous and environmentally safe. The tagged proppant is activated (after it has been placed in the fracture) by a logging tool that contains a neutron source. The activated tag emits gamma rays at a characteristic energy level that can be detected by the logging tool. Analysis of the data (from the logging run) not only identifies the location of the tagged proppant, but can also be used to develop other valuable information including propped fracture width in the near wellbore region. The resin coated proppant containing the tag is manufactured in such a manner as to assure that the concentration of the tag in the coating is held at a constant throughout the coating process. Since the level of gamma ray emission is a function of the amount of tag irradiated by the logging tool, the count rate detected by the tool is proportional to both the concentration of the tag and the concentration of the tagged proppant that has been irradiated. Based on these factors, analysis of the logging data not only yields the location of the tagged proppant, but leads to a more accurate calculation of the propped fracture width as compared to previous methods. This paper will detail the test procedures and resulting data that contributed to the development of this new method to calculate propped fracture width. This method of propped fracture width calculation will then be applied to a variety of actual field applications of the tag technology. The calculated propped fracture width results from the field tests will be presented and discussed in detail. Introduction It is important to generate all possible information on the geometry generated by a fracturing treatment. In the low permeability reservoirs (that make up so much of the domestic production) the economic success of the well is often directly related to whether the fracturing treatment generated the desired geometry within the targeted intervals.

For years, radioactive tracers have been used in combination with standard industry logging tools to gain valuable insight about the fracture height (near-wellbore vertical coverage) of proppant-packed fractures. The existing tracer technology has a number of safety and environmental issues that must be addressed when using this technology as part of a fracturing treatment. These issues, along with regulations concerning the transportation of radioactive materials, have impacted the application of this technology in international markets. This paper will describe a new patent-pending technology that can generate valuable data on propped fracture height, as well as insight into propped fracture width. In this new technology, a non-radioactive tagging additive is incorporated into the resin coating of the proppant. This non-hazardous, environmentally safe, coated proppant can be transported and applied without any of the restrictions associated with radioactive tracers. Once the proppant is placed in the well, a gamma spectroscopy logging tool is used together with a fast neutron source to activate the tagging additive. The additive then becomes temporarily radioactive, emitting characteristic gamma rays that are visible to the logging tool's spectrometer. The detected gamma ray response not only identifies the presence of the proppant, but in addition, the strength of the response is proportional to the amount of the additive/proppant that is present in the fracture, thereby providing insight on fracture width. Since the additive only responds when stimulated by the neutron source, the logging process can be completed free of any of the timing constraints associated with the half-life of presently used radioactive tracers and can be repeated as often as desired. The additive used in this technology has been selected for a number of reasons, not the least of which is its very short half-life after being irradiated. By the time the logging process is complete and the well is ready to be placed in production, the additive will no longer emit a detectable level of radiation. This paper will describe this technology and its use in some detail. It will also present the results of initial field tests that utilized this new technology to determine aspects of propped fracture geometry. Introduction Ever since the first use of hydraulic fracturing, the oil industry has wanted information about the geometry of what wascreated. The desired geometry is most often referred to as propped length, width, and height. Early efforts focused on logging temperature profiles after a frac job. This technique was based on the "cooling effect" that was created when the fracturing fluid was injected into the formation interval. Although this analysis gave indications of which parts of the interval had accepted fluid, it didnot give the desired information on the location of the proppant that had been pumped. In more recent times, the use of radioactive tracers has grown in acceptance. Due to the inherent inaccessibility of the downhole environment, radioactive tracers have represented one of the few viable means for analyzing the placement and flow of various processes and materials¹. Radioactive tracers have been found to be useful in developing information in virtually all aspects of drilling, completing, and producing a well. A particularly popular use of radioactive tracers is for the determination of propped fracture height. Fracture height measurement through the use of radioactive tracers and subsequent logging runs allow engineers to assess2:Post stimulation problems such as lower than expected productionDesign assumptionsPossible modifications to future stimulation treatment designs

One of the more important aspects of any fracturing treatment is the proppant that is used. In some instances, particularly in deep well applications, the type of proppant used can make a difference between the treatment being an economic success or failure. As job size increases, the price of the proppant becomes a significant percentage of the proppant becomes a significant percentage of the overall treatment cost. This is especially true if the various high strength proppants are to be used. This paper deals with a fracture permeability study of many of the available low and high strength proppant materials. In each case, fracture proppant materials. In each case, fracture permeability is measured as a function of closure stress. permeability is measured as a function of closure stress. Using the apparatus described in this paper, the relative permeabilities of each proppant are obtained using identical testing procedures. Many current treatments incorporate both frac sand and one of several more expensive high strength proppants. For this reason, special emphasis is placed on test results obtained from mixtures of the high strength proppant and the more economical frac sand. proppant and the more economical frac sand. To illustrate the effect that various proppants or proppant mixtures have on the results obtained from a fracturing treatment, a computer analysis is made. The analysis will indicate the effect of fracture permeability on estimated production increase and the effect of proppant choice on the economics of the treatment. From this analysis and the permeability data reported, guidelines for the choice of a permeability data reported, guidelines for the choice of a proppant or mixture of proppants are set up for proppant or mixture of proppants are set up for shallow, medium and deep well application. Introduction The use of hydraulic fracturing, as a method for increasing well production, has risen significantly in recent years. This trend will continue as it becomes increasingly important to maximize the amount of oil or gas that can be produced from a given well. In the past, most pre-job planning centered around decisions concerning the type of fracturing fluid to be used or the pump rate and treating pressure to be encountered. Little, if any, time has spent on the choice or combinations of proppants to be used. As treatment costs rise, increased design time is being spent on all aspects of the treatment. Until recently, there have been relatively few significant changes in the proppants used in hydraulic fracturing. By far the most common proppant consists of a specially screened, high grade sand (usually 10–20 or 20–40 mesh). As well depths increased, it became apparent that higher strength proppants were required. The first such proppant to proppants were required. The first such proppant to gain widespread use was glass beads. Recent advances have resulted in the development of the new sintered bauxite proppant. In order to take full advantage of all the available proppants, it is necessary to determine certain well parameters, in particular, the amount of closure pressure exerted by the fracture faces on the proppant. Once this value has been calculated, the proppant. Once this value has been calculated, the permeability of the proppant at reservoir conditions permeability of the proppant at reservoir conditions can be evaluated and the economics of the treatment and its results estimated. Presented in this paper are the relationships between fracture permeability and closure pressures for the following list of proppants:10–20 and 20–40 Hickory Sand (Heart of Texas or San Saba frac sand)20–40 St. Peters Deposit (Ottawu or Gopher State frac sand)12–20 and 20–40 Glass Beads20–40 Sintered Bauxite100 Mesh Sand (Oklahoma #1)Mixtures of Hickory Sand and Glass Beads