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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.

Summary The primary purpose of surfactants used in stimulating sandstone reservoirs is to reduce surface tension and contact angle and provide leakoff control. However, many of these chemicals adsorb rapidly within the first few inches of the sandstone formations, reducing their effectiveness in deeper penetration. This phenomenon causes surfactants to adsorb or plate-out, reducing their effectiveness in post-fracturing fluid recovery. This study describes experimental and field-case studies of various surfactants used in the oilfield. Several different surfactants, including a nonionic ethoxylated linear alcohol, a nonyl phenol ethoxylate, an amphoteric, a cationic, and a microemulsion system were investigated to determine their adsorption properties when injected into a laboratory sandpacked column. A laboratory-simulated comparison study of commonly used surfactants and microemulsion was used to identify their leakoff and waterrecovery properties from gas wells. Field data collected from Bradford, Balltown, and Speechley sandstone formations confirmed experimental sandpacked column and core-flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional surfactant treatments. Wellhead pressures, flowing pressures, and production data were collected and evaluated using a production simulator to show effective fracture lengths, damage surrounding the fractures, and drainage areas with various fluid systems. These investigations and presented case studies can be used to minimize formation damage.

Acid stimulation of horizontal wellbores in high temperature and/or low permeability formations is complicated due to the need to balance acid reaction rates with the rate of formation penetration. At high bottom hole temperatures, uncontrolled acid spending rates result in inefficient or even damaging treatments. It is advantageous to add materials which slow the reaction of HCl or use alternative acids which are useful as alternative stimulation fluids, such as organic acids and chelants due to their inherently lower reaction rates. The slower reaction rate with carbonate minerals allows for optimal wormhole growth at the limited rates available in long horizontals. This study investigates the complementary use of acid or chelant systems together with a microemulsion delivery system to achieve the desired performance. These delivery systems can significantly increase the efficiency of HCl and chelant stimulation treatments of low-permeability carbonates by optimizing diffusivity and minimizing pressure to cleanup. Horizontal core flow experiments were conducted by injecting solutions of 15 wt% HCl and 10–20 wt% alternative acids through low permeability (< 10 md) limestone cores. High permeability cores were also investigated by injecting 15 wt% HCl through high permeability (150–200 md) Indiana limestone cores. These experiments were conducted with and without the addition of a microemulsion additive and at core injection rates from 0.2 – 20 cm3/min corresponding to 0.25 to 5 BPM per 100 ft of a horizontal wellbore. Significant performance advantages were found with the addition of the microemulsion delivery system. The treatment volume required for wormholes to propagate the length of the test core was reduced at all flow rates at or above the optimum rate. Core penetration was more efficient when using the microemulsion, without an increase in pumping pressure. Initiation and extension of wormholes was improved, as compared to the experiments without the microemulsion, in which more conical wormholes tended to form at the inlet face. The reduction in treatment volume necessary to reach breakthrough with the microemulsion present also suggested a more efficient treatment. The complementary use of a microemulsion delivery system with acids and chelants has been shown to enhance acid stimulation treatment potential in long horizontal wellbores with high temperature or low permeability formations. This system can be used to optimize wormhole penetration while maintaining an optimum injection rate across long horizontal intervals where the maximum achievable injection rate is relatively low.

ADMA OPCO has started operations for a full field development plan in a green field located in offshore Abu Dhabi. All reservoirs are carbonates (dolomites and limestones) and thus acid stimulation is required post well completion in order to increase the well production/injection rate. During the planning stage, an extensive acid recipe study was carried out to formulate stimulation treatments to meet the challenging complexities of the reservoirs, high downhole temperatures and long corrosion protection time. Several lab tests were carried out to formulate all the acid recipes. While in quest of new technology, an additive called ‘Complex Nano Fluid’ was introduced in the acid recipes based on proven case histories from around the world. This was also confirmed with the lab tests using ADMA reservoir crude and core samples. It is expected that by including nano fluids in matrix stimulation fluids, the overall productivity enhancement will be approximately 40% greater than conventional treatment approches. Most of the tests were performed in Abu Dhabi, however special wormholing tests with CT scan were done in a lab in Houston to evaluate the effectiveness of nano fluids on core samples. This paper details the acid recipe work flow process, the different lab tests that were carried out to formulate the acid recipes, mechanism of complex nano fluid and its advantages.

Abstract The productivity and economics of horizontal wells are governed by the ability of the transverse fractures to communicate efficiently with the wellbore, which is strongly controlled by the conductivity of the proppant bed and the effectiveness of the fluid additives. These impact the relative permeability, the capillary pressure and the effective conductivity in the proppant bed. If the wellbore is high in the fracture, gravity segregation will cause liquid removal from the lower portion of the fracture to be very difficult. In low conductivity proppant beds, capillary pressure will tend to retain high water saturations, thus lower the effective conductivity even for the portions of the fracture above the wellbore. Laboratory and field studies are presented comparing various sizes and types of proppants and the influence of surfactants used in oil bearing formations including commonly used demulsifiers and a multi-phase complex nano fluid system. Ammot cell and centrifuge tests were used to evaluate imbibition of oil and water. Columns packed with proppant and formation cuttings are used to compare the effectiveness of various additives in allowing the displacement of water and establishing oil flow. Results are correlated with interfacial tension, contact angle, capillary pressures and surface energies of actual formation materials, oils and treating fluids from the Niobrara, Bakken, Granite Wash and Eagleford formations. Simulations are presented that show the impact of capillary pressure and oil viscosity on the displacement of fluids. Field results from various fields including the Niobrara, Bakken, and Marcellus formations are presented. The normalized field data shows that wells with higher conductivity proppants and properly selected surfactant packages result in longer effective frac lengths and greater normalized oil and gas production. Correlations are made between the observed relative perms in the lab vs. the observed field results.

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.

The primary purpose of using surfactants in stimulating hydrocarbon rich gas reservoirs is to reduce interfacial tension, and/or modify contact angle and reservoir wettability. However, many surfactants either adsorb rapidly within the first few inches of the formation, or negatively impact reservoir wettability, thus reducing their effectiveness in lowering capillary pressure. These phenomena can result in phase trapping of the injected fluid adversely impacting oil and gas production. This study describes experimental and field studies comparing various common surfactants used in oil bearing formations including alcohol ethoxylates, EO-PO block copolymers, ethoxylated amines and a multi-phase complex nano fluid system to determine their impact on oil recovery and adsorption tendencies when injected through 5-foot and 1 ft sand columns. Ammot cell tests were used to evaluate imbibition of oil and water and a core flow apparatus was used to evaluate regained relative permeabilities. The results are correlated with surface energies of actual formation materials, oils and treating fluids. The results are used to select formulations containing surfactant, solvents and co-solvents to apply within the fracturing fluid to decrease adsorption, eliminate post treatment emulsions and improve oil and gas recovery in hydrocarbon rich gas wells.

Formation damage caused by water-in-crude oil emulsions can have a big impact on oil production. Chemical treatment is often applied by injecting surfactants known as demulsifiers to break the water-in-crude oil emulsions. Common demulsifiers used in the oilfield industry often contain chemicals that are deemed environmentally unacceptable. With the increasingly stringent environmental and safety measures for oilfield chemicals, there is a significant drive to develop more environmentally friendly formulations for oilfield applications that are as efficient as existing chemicals. In this work, more environmentally friendly demulsifiers have been developed by systematically upgrading existing components in a conventional demulsifier with more environmentally acceptable components. The environmental impact of existing and upgraded formulations was evaluated using industry developed product rating systems. Demulsification tests were then carried out to assess the performance of the newly developed formulations on several problematic oils.

The productivity and economics of horizontal wells are governed by the ability of the transverse fractures to communicate efficiently with the wellbore, which is strongly controlled by the conductivity of the proppant bed and the effectiveness of the fluid additives. These impact the relative permeability, the capillary pressure and the effective conductivity in the proppant bed. When time at temperature, stress cycling, embedment, multi-phase flow and non-Darcy effects are considered, the effective conductivity can be reduced 100-fold. Another investigated parameter is the impact of the wellbore location relative to the propagated fracture. If the wellbore is high in the fracture, gravity segregation will cause liquid removal from the lower portion of the fracture to be very difficult. In low conductivity proppant beds, capillary pressure will tend to retain high water saturations, thus lower conductivity even for the portions of the fracture above the wellbore. Laboratory experiments have addressed these issues for proppants with a range of permeabilities from 10 to 100 Darcies; 100 mesh to 20/40 mesh and ceramics. The relative permeability to gas can be as low as 0.01, with as much as a 70-fold improvement when suitable proppants and additives are employed. Evaluation of the production performance of 240 wells, 98 with effective additives and 142 without, and covering a similar range of proppant types and sizes, shows a similar benefit to the wells’ normalized 30 day recovery and gross value. These results clearly demonstrate that economic expediency can be detrimental to a well’s ultimate value and hydrocarbon recovery.

In recent years numerous case studies documenting the use of microemulsions in hydraulic fracturing of tight gas formations have appeared in the literature. Field case studies and supplemental laboratory data have illustrated that microemulsions enhance core permeability to gas and enhance fluid flowback mainly due to lowering capillary pressure and altering wettability in reservoirs and propped fractures. Although proven successful for enhancing gas production, many aspects of the microemulsion behavior in propped fractures are still poorly understood. In the present study we have performed numerous experiments on microemulsion-assisted fluid recovery from columns packed with sand proppant and shale, using microemulsions of different chemical composition. Our results indicate that the extent to which microemulsion additives promote foaming is an important factor in achieving highest possible levels of fluid recovery. By using properly formulated microemulsion compositions one can achieve significant improvement in fluid recovery at commercially viable doses of treatment.

Hydraulic fracturing of shale formations presents a well-known challenge due to high entrapment of frac fluids. Typical levels of fluid recovery from shale formations are on the order of 30% or lower. Fluid loss into shale produces liquid blocks that interfere with the gas flow in already tight formations. Friction reducers or other additives present in fluids can cause further formation damage. Search for technologies that would maximize gas flow rate and yield high recoveries is ongoing. In recent years microemulsions have been successfully used for remediating damaged wells and enhancing production from tight gas formations. In the present work we have explored the use of such additives for improving fluid recoveries from columns packed with shale/sand mixtures and for improving permeability of split shale cores to gas.

An extensive, on-going investigation into the effectiveness of a micro-emulsion (ME) as a stimulation fluid additive is being conducted. Results from a population of 114 wells and 498 stimulation stages of hydraulic fracture stimulation provide the basis for this report. As part of the basis for the performance analysis, twenty four of the wells are producing from the Lance interval in the northeastern Pinedale Anticline area of the Green River Basin, Wyoming. The remaining 90 wells produce from the northern Denver-Julesburg Basin Codell and Niobrara formations. In both data sets about half of the wells had 1.5 gallons of ME per thousand used throughout the fracture stimulations, but at no other time during in-well operations. The stimulation fluid systems in the remaining wells contained no similar interfacial tension / surfactant system. Based on the performance matched reservoir properties and degree of effective stimulation, these comparisons and other performance metrics were used to assess the potential benefit arising from using ME. The determination of potential benefit was assessed using classical statistical methods to ensure that the interpretation was as unbiased as possible. From that analysis, there is distinct and clear benefit to be gained from using the micro-emulsion to facilitate placing the fracture stimulations, to increase effective fracture length and especially to increase hydrocarbon recovery from the wells in which the micro-emulsion system is used.

In the petroleum industry, water and oil emulsion formation presents an on-going production issue receiving considerable technical attention. Crude oil/water demulsification effectiveness has been tested using a new microemulsion-based demulsifier (ME-DeM) with an environmentally improved formulation. This ME-based product, tested on a range of crude oils, has been shown to be more effective than comparable commercially available non-ME based demulsifiers (DeM). Results using ME based products for demulsification have demonstrated significant improvements in field tests. Additional field studies are in preparation.

The evaluation of 24 wells representing 339 stages of fracture stimulation which produce from the Lance interval in the northeastern Pinedale Anticline area of the Green River Basin, Wyoming has been conducted to determine if the use of a micro-emulsion (ME) surfactant intended to reduce permeability impairment and improve load recovery, had any observable benefits. The well group consisted of wells in a limited contiguous six square mile area, with 10 wells having 1.5 gallons of ME per thousand used throughout the fracture stimulations, but at no other time during in-well operations. Fourteen wells completed approximately nine months earlier had no micro-emulsion used during stimulation or other in-well operations. Based on the matched reservoir properties and effective degree of stimulation, 20 year forecasts were performed for each well. Then comparisons of those results and various treating parameters were used to assess the potential benefit arising from using ME. The determination of potential benefit was assessed using classical statistical methods to ensure that the interpretation was as unbiased as possible. From that analysis, there is distinct and clear benefit from using the micro-emulsion to facilitate placing the fracture stimulations, to increase effective fracture length, to minimize damage arising from operational shut-ins and especially to increase gas recovery and net present value of wells in which the micro-emulsion system is used.

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?

In 2001, the International Organization for Standardization (ISO) and American Petroleum Institute (API) formed a new committee to write procedures for measuring the properties of proppants used in hydraulic fracturing. API Recommended Practices (RP) for testing of proppants are generally "reviewed and revised, reaffirmed, or withdrawn at least every five years" in accordance to API instructions. The last Recommended Practice was published in December 1995. The committee was charged with re-writing API RP 56, 58, and 60 relating to sand as a proppant, gravel packing, and high strength proppants, respectively. This new document, ISO 13503-2 "Measurement of Properties of Proppants Used in Hydraulic Fracturing and Gravel-Packing Operations" is a standard. Any company may follow these procedures and state on their published data that they followed ISO procedures to generate the specifications of their product. Several changes have been made to the Recommended Practices, and the goal of this paper will be to highlight these changes, and to discuss the potential impact on the proppant industry. In 2003 a second committee was formed to write procedures on measuring long term conductivity of a proppant pack. The industry was using for years a procedure based on API RP 61 "Recommended Practices for Evaluating Short Term Proppant Pack Conductivity" 1989, which is an obsolete document. Roughly a dozen facilities worldwide are running long term conductivity tests, all slightly different. Recent advances in technology have been incorporated in this standard to increase the accuracy of the results, and to standardize the equipment and testing procedures. The new standard is ISO 13503-5 "Procedures for Measuring the Long-Term Conductivity of Proppants". These two new procedures will enable users to evaluate and to compare proppant characteristics under the specifically described test conditions for use in hydraulic fracturing operations. They are not designed to provide absolute values of proppant conductivity under downhole reservoir conditions. Test data has shown that time, elevated temperatures, fracturing fluid residues, cyclic stress loading, embedment, formation fines, and other factors will further reduce proppant pack conductivity.

The primary purpose of stimulating fractured shale reservoirs is the extension of the drainage radius via creation of a long fracture sand pack that interconnects with natural fractures thereby establishing a flow channel network to the wellbore. However, there is limited understanding of a successful method capable of stimulating Utica Shale reservoirs. Indeed, most attempts to date have yielded undesirable results. This could be due to several factors, including formation composition, entry pressure, and premature pad fluid leak-off. Furthermore, stimulation of Utica shale reservoirs with acid alone has not been successful. This treatment method leads to a fracture length and drainage radius less than expected, resulting in poor well productivity. In this work, geological data is first examined for the reservoir. Laboratory data are then presented to address the unique mineralogy and mechanical properties of the Utica Shale. The high percentage of acid soluble carbonate and dolomite suggests an acid treatment to lower entry pressures. This treatment can be the main stimulation of a vertical or horizontal well since natural fractures are present, or the acid breakdown can precede a gelled acid or proppant-laden water frac or crosslinked fracturing fluid treatment. Experimental results reveal the impact of clays, potential generation of fines both siliceous and organic, acid solubility, low temperature biological activity, potential for scale generation and the prevalent problem of recovery of injected fluids. Acid solubility is presented vs. time and acid strength. Conductivity data is presented for gas fracs, matrix acidizing and proppant fracturing of the shale. The adsorption, as well as the regained relative permeability to gas is examined vs surfactant type to allow the selection of an additive package that will optimize fluid recovery and improve relative permeability to gas. Information obtained from this study can be used to optimize fracturing treatments of Utica Shale reservoirs in the Appalachian Basin. As interest in drilling and producing shale reservoirs throughout North America increases due to the success of the Barnett, Woodford, and Fayetteville shales, numerous potential reservoirs that have previously been undeveloped are being examined for their potential. The organic-rich, low-permeability Upper Ordovician Utica Shale is one such reservoir that displays many attributes which may result in a commercially viable play of great areal extent. This interest is driven largely by increased natural gas prices and improved completion technologies. Indeed, there may be no better example of the role of technology in natural gas recovery than the Late Mississippian Barnett Shale of the Fort Worth Basin, which provides an analog for exploration of similar unconventional reservoirs throughout North America. Nevertheless, there is no universal production model method of stimulating each and every unconventional reservoir that exists. The Utica Shale compares favorably with such organic-rich units as the Middle Devonian Marcellus Shale of the Appalachian Basin and the Upper Cretaceous Lewis Shale of the Green River Basin. Nevertheless, most unconventional reservoirs vary in terms of basic stratigraphic facies distribution, mineralogy (i.e., quartz content, clay type and content), natural fracture parameters (length, orthogonal spacing, connectivity, anisotropy), porosity and permeability, and rock mechanical properties. The tight, organic-rich black shale deposits generating the interest of explorationists are the Utica Shale and the Devonian Marcellus and Rhinestreet shales of the Appalachian Basin. A previous publication described promising results of an experimental investigation of hydraulic fracturing and post-fracturing cleanup of the Upper Devonian Rhinestreet Shale of the Appalachian Basin. However, several recently drilled Utica Shale wells have not responded well to the normal shale fracturing practices. An understanding of Utica Shale mineralogy and rock mechanics is necessary before a stimulation method and fluid are selected. The main objective of this paper is to examine methods of stimulating the Utica Shale. An overview of the geology of the Utica Shale is presented first. Laboratory data are then examined to address the unique mineralogy and mechanical properties of the Utica Shale. The high percentage of acid soluble carbonate and dolomite suggests that an acid treatment to lower entry pressures will be required. This treatment may be the main stimulation of a vertical or horizontal well since natural fractures are present, or the acid breakdown can precede a gelled acid or proppant-laden water frac or crosslinked fracturing fluid treatment. Experimental results reveal the impact of clays on extraction, potential generation of fines both siliceous and organic, acid solubility, low temperature biological activity, the potential for scale generation and the prevalent problem of recovering injected fluids. Acid solubility vs. time and acid strength is also presented. Conductivity data for gas fracs, matrix acidizing and proppant fracturing of the shale is considered. The adsorption as well as the regained permeability to gas is examined vs. surfactant type to allow the selection of an additive package that will optimize fluid recovery and improve relative gas permeability. Figure 1. Map showing the thickness of the Utica Shale in New York State and northern Pennsylvania. Figure 2. Simplified stratigraphic column of the Upper Ordovician interval of New York State (modified not to scale).

Field data and lab data are presented for various fluids pumped in low perm shales, coalbed methane and tight sandstone reservoirs. Commonly used surfactants, alcohols as well as a microemulsion system (ME) are evaluated. Lab data is presented that illustrates the cleanup of injected fluids in tight gas cores. Damage mechanisms are shown to be phase trapping and high capillary pressures. The microemulsion additive results in lower pressures to displace injected fluids from low permeability core samples over conventional surfactant and methanol treatments. The observed enhanced relative permeability mechanism is the alteration of the rock-fluid interfacial tension or contact angle. It is demonstrated that this alteration effectively lowers the capillary pressure and capillary end effect associated with wellbores and fractures in low perm reservoirs by as much as 50%, thus mitigating phase trapping and therefore permitting an increased flow area to the wellbore following drilling and hydraulic fracturing. Over 300 wells were evaluated that were drilled and/or fracture treated with various fluid combinations in the Barnett, Fayetteville and Appalachian basin shales. Some 200 wells are examined in the San Juan Basin and other low perm areas such as the Pieance Basin, Uinta, Vicksburg and Cotton Valley. Drilling examples are shown for several horizontal wells. The addition of the microemulsion to fracturing treatments has resulted in more than 50 to 100% increases in load recoveries and gas production. Production analysis of horizontal wells drilled and cleaned up with the microemulsion shows a doubling of production over offsets. Pressure analysis of fractured wells shows that the damage factor is reduced by a factor of 2 with the inclusion of ME. This is a result of a combination of reduced depth of invasion, a higher relative perm in the invaded zone and/or longer effective frac lengths.

A study of completion techniques in depleted/low pressure tight permeability gas/oil reservoirs shows great promise through the use of a microemulsion (ME) additive in energized fracture stimulation treatment of new infill wells. This paper presents a comparison of four (4) wells completed according to historical stimulation practices and two (2) wells completed with microemulsion additive. See Table 1 for baseline data. The damage mechanisms from past practices were exacerbated by depleted/ low bottom-hole pressures, high water saturations, and low bubble point crude. The use of the microemulsion additive reduced the liquid load and promoted liquid recovery, enabling the base fluid gases to establish gas saturated pathways and promote the production of the natural solution gas that is the field's primary economic resource. CO2 is thought to enhance this process by promoting the reduction of the near fracture face oil saturation. The microemulsion potentially enhances this action by reducing the mobility contrast between introduced fluids and reservoir oil, water, and gas phases. Analysis of the production histories shows that the microemulsion additive significantly enhanced the reservoir conductivity and effective fracture length when compared to the historical completions when in sustained production. The two wells treated with microemulsion additive also experienced less damage as a consequence of the long shut-ins prior to sustained production, than did those with historical completions, which had much shorter shut-ins.

The primary purpose of surfactants used in stimulating sandstone reservoirs is to reduce surface tension, contact angle and leakoff control. However, many of these chemicals adsorb rapidly within the first few inches of the sandstone formations, reducing their effectiveness in deeper penetration. This phenomenon causes surfactants to adsorb or plate-out reducing their effectiveness in post fracturing fluid recovery. This study describes experimental and field case studies of various surfactants used in the oilfield. Several different surfactants including a nonionic ethoxylated linear alcohol, nonyl phenol ethoxylate, an amphoteric, a cationic and a microemulsion system were investigated to determine their adsorption properties when injected into a laboratory sand packed column. A laboratory simulated comparison study of commonly used surfactants and microemulsion was used to identify their leakoff and water recovery properties from gas wells. Field data collected from Bradford, Balltown and Speechley sandstone formations confirmed experimental sand packed column and core flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional surfactant treatments. Wellhead pressures, flowing pressures and production data were collected and evaluated using a production simulator to show effective fracture lengths, damage surrounding the fractures and drainage areas with various fluid systems. These investigations and presented case studies can be used to minimize formation damage.

In this work field data and lab data are presented for various fluids pumped in the Barnett Shale. Recent fracture treatments have been light sand fracs in slick water consisting of water and friction reducer, with and without surfactants. Commonly used surfactants as well as a microemulsion system (ME) are evaluated. Lab data is presented that illustrates how the microemulsion accelerates the cleanup of injected fluids in tight gas cores. The microemulsion additive results in lower pressures to displace injected fluids from low permeability core samples and proppant packs. The relative perm to gas is increased substantially as the water saturation is decreased. The enhanced relative permeability mechanism is the alteration of the rock-fluid interfacial tension or contact angle. It is demonstrated that this alteration effectively lowers the capillary pressure and capillary end effect associated with fractures in low perm reservoirs by as much as 50%, thus mitigating phase trapping and therefore permitting an increased flow area to the fracture, hence longer effective frac lengths. Over 200 wells have been treated and analyzed in the Barnett Shale for this study. Several side by side comparisons of treatment variations are possible. The addition of the microemulsion to fracturing treatments has resulted in more than 50% increases in load recoveries and 30-40% increases in gas production. Pressure analysis of fractured wells shows that the damage factor is reduced by a factor of 2 in the Barnett shale with the inclusion of ME. This is a result of a combination of reduced depth of invasion, a higher relative perm in the invaded zone and/or longer effective frac lengths.

A new technical standard is developed to measure rheology of completion fracturing fluids. This method details step-by-step procedure for making fluids and rheology measurements. Completion fluids are defined for the purpose of this technical standard as viscosified treating fluids used during the completion or workover of a petroleum or natural gas producing well. The objective of this technical standard is to provide a standard procedure for measuring the viscous properties of single-phase, non-particulate-laden completion fluids. These fluids are viscosified brines, gravel pack carrier fluids, and fracturing fluids. These fluids can be either crosslinked or non-crosslinked (aqueous, hydrocarbon, or acid based). An optional shear history simulation procedure is provided for fluids that are potentially shear-sensitive. This procedure is designed to simulate the shearing effects experienced by a fluid in surface apparatus and during the time it is being conveyed down the wellbore.

The primary purpose of surfactants used in stimulating Sandstone reservoirs is to reduce surface tension. Conventional surfactants adsorb rapidly within the first few inches of the sandstone formations, thus losing their effectiveness as the treating fluid leaks off. This results in trapped fluids and poor post fracturing fluid recovery. A surfactant solvent system in the form of a microemulsion can also be used to not only lower surface tension at very dilute concentrations, but alter contact angle and lower capillary pressure to further improve recovery. The unique microcells are also effective in controlling leakoff. This study describes the laboratory experiments and field case studies of various surfactants used in the oilfield. Several surfactants including an ethoxylated linear alcohol, a nonyl phenol ethoxylate and a microemulsion system were investigated to determine their adsorption properties when injected into laboratory sand packs. Laboratory studies were also conducted to compare the leakoff and water recovery properties from gas wells. Field data collected from Bradford and Speechley sandstone formations confirms experimental sand pack and core flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional surfactant treatments. Wellhead pressures, flowing pressures and production data were collected and evaluated using a production simulator to show effective fracture lengths and drainage areas with various fluid systems. Lab and field data collected in these studies from Appalachian Basin reservoirs illustrates that the addition of a microemulsion to a fracturing fluid exhibits significant advantages over the conventional surfactant treatments when water recovery, increased effective fracture length and well productivity are of concern to the operator.

The primary purpose of surfactants used in stimulating sandstone reservoirs is to reduce surface tension of the fracturing fluid, decrease interfacial tension between injected fluid and reservoir rock and increase post-fracturing fluid recovery. However, many of these chemicals when injected at high pressures adsorb rapidly into the sandstone formation, reducing their effectiveness in post fracturing fluid recovery. This study describes simulated laboratory experiments and case histories of various surfactants used in the oilfield. Several different surfactants including ethoxylated linear alcohol, nonyl phenol ethoxylate and a microemulsion system were investigated to determine their adsorption properties when injected into a sand packed column. A laboratory simulated comparison study of these surfactants versus a microemulsion system was used to identify their water recovery properties from gas wells. Field data collected from Benson, Balltown, Injun, and Speechley Sandstone formations confirm experimental sand packed column and core flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional non-emulsifying surfactant treatments. Case histories reported from several gas wells stimulated in the Appalachian Basin illustrate the advantages microemulsions have over conventional surfactant treatments when faster cleanup, increased post fracturing fluid recovery and well productivity are of concern to the operator.

A new microemulsion additive has been developed that is effective in remediating damaged wells and is highly effective in fluid recovery and relative permeability enhancement when applied in drilling and stimulation treatments at dilute concentrations.The microemulsion (ME) is an optically clear, thermodynamically stable blend of biodegradable solvent, surfactant, co-solvent and water.The nanometer sized structures have extremely high contact efficiency at low concentrations (0.10-0.5%). Lab data is presented that illustrates how the Microemulsion accelerates the cleanup of injected fluids in tight gas cores. The microemulsion additive results in lower pressures to displace injected fluids from low permeability core samples and proppant packs. The relative perm to gas is increased substantially as the water saturation is decreased. The enhanced relative permeability mechanism is the alteration of the rock-fluid interfacial tension or contact angle.It is demonstrated that this alteration effectively lowers the capillary pressure and capillary end effect associated with fractures in low perm reservoirs by as much as 50%, thus mitigating phase trapping and therefore permitting an increased flow area to the fracture and longer effective frac lengths.Examples of drilling fluids with and without ME are shown in which the relative perm to gas and oil are improved with the application of the microemulsion system. Field examples are shown for fracture treatments of unconventional low permeability coals and shales, where water recovery and productivity are increased by 50% with the application of ME. A production analysis is presented for wells treated in the Barnett Shale that shows longer effective frac lengths and decreased damage surrounding the fracture.

A new microemulsion additive has been developed that is effective in remediating damaged wells and is highly effective in fluid recovery and relative permeability enhancement when applied in drilling and stimulation treatments at dilute concentrations. The microemulsion is a unique blend of biodegradable solvent, surfactant, co-solvent and water. The nanometer-sized structures are modeled after Veronoi structures which when dispersed in the base treating fluid of water or oil permit a greater ease of entry into a damaged area of the reservoir or fracture system. The structures maximize surface energy interaction by expanding to twelve times their individual surface areas to allow maximum contact efficiency at low concentrations (0.1–0.5%). Higher loadings on the order of 2% can be applied in the removal of water blocks and polymer damage. Lab data are shown for the microemulsion in speeding the cleanup of injected fluids in tight gas cores. Further tests show that the microemulsion additive results in lower pressures to displace frac fluids from propped fractures resulting in lower damage and higher production rates. This reduced pressure is also evident in pumping operations where friction is lowered by 10–15% when the microemulsion is added to fracturing fluids. Field examples are shown for remediation and fracture treating of coals, shales and sandstone reservoirs, where productivity is increased by 20–50% depending on the treatment parameters. Drilling examples are shown in horizontal drilling where wells cleanup without the aid of workover rigs where offsets typically require weeks of workover.

Sereens are used to mechanically restrain formation solid entrance to a wellbore. As effective as this process may be, in many cases it fails to retain solids. This is due to screen plugging either during screen run in a wellbore or during production where larger size particles bridge against a screen and finer size particles plug the screen. In either case, plugged screens are subjected to a cleanup treatment. In this paper, a series of large-scale tests are conducted to evaluate screen cleanup methods such as acid spotting, use of enzyme and acid activated-breaker, backflow, and a combination of these methods under downhole conditions. At first, each screen's retention performance is evaluated. Then, a drill-in-fluid containing solids is pumped into a large-scale flow-cell at a constant pressure drop across the screen to simulate a screen run down in a wellbore. Inlet and outlet samples are collected to evaluate removal efficiency of each screen. Then, each plugged screen is subjected to a cleanup method. The effectiveness of each cleanup technique is evaluated based on the retained permeability of each screen. Degree of plugging and percent area open to flow for each screen is also presented.

Some of the completion failures are due to screen plugging. A number of remedies have been adopted by the industry to cleanup plugged screens. However, these cleanup methods are not investigated under downhole conditions. This study utilized a large-scale radial flow-loop to study prepacked screen cleanup under downhole conditions. First, the original permeability of each screen was measured with 10 ppg NaCl brine solution. A sized carbonate drill-in-fluid was then formulated and pumped for 3 hours and at a constant differential pressure of 60 psi across the screen, simulating a screen run in a wellbore. Inlet and outlet samples were collected for size distribution analysis and removal efficiency calculations of each screen. Each plugged screen was then subjected to a cleanup method such as acidizing, use of enzyme breaker, backflow, or a combination of these methods. Following cleanup, the permeability of each treated screen was measured with 10-ppg NaCl brine solution and compared to the screen's original permeability. The degree of plugging and percent area open to flow was evaluated based on the retained permeability of each screen.

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.

A large-scale radial flow cell was utilized to characterize 0.004 in. gauge, 0.006 in. gauge, and 0.008 in. gauge 40/60 resin coated prepack screens based on retention testing. In addition, screen cleanup methods such as backflow (flowing water in the injection and production directions), 10% hydrochloric acidization at 120°F, enzyme soaking, and the use of breaker were evaluated on damaged screens. A carbonate drill-in-fluid (DIF) containing 5000 and 10,000 PPM solids was formulated and pumped for three hours at 16 gpm and 120°F into the flow cell and around the screen at a constant 60 psi differential pressure across the screen. Effluent samples of drill-in-fluid were collected to measure total solids. Removal efficiency of each screen was then calculated. Damaged screens were then subjected to one or a combination of various cleanup methods. Permeability of the treated screen was measured to 10-ppg NaCl brine solution and was compared to the screen's original permeability. The degree of plugging was evaluated based on the retained permeability of each screen after being subjected to one of the cleanup methods.

This paper describes the development and use of laboratory data to show the impact of multiphase, non-Darcy flow and gel damage upon gas production from hydraulic fractures. In the work, the percent cleanup is related to the molecular weight and concentration of the gel remaining in the proppant pack and the inertial force available from the flow of gas and liquids during cleanup and production. The impact of proppant permeability and multiphase, non-Darcy flow is further combined with inertial force and gel damage to provide a newly developed relationship to predict the degree of cleanup. The new relationship can be used to calculate the effective conductivity for various proppant types, sizes and concentrations vs. closure, temperature, gel and breaker concentration, and prevailing gas/water/oil ratios. The calculated effective conductivities can then be used to predict gas productivity and economics under various conditions of multiphase, non-Darcy flow. The results of the testing show that multiphase, non-Darcy flow dramatically increases the difference between the effective conductivities of various proppants and fracturing fluids with different retained permeabilities. The laboratory data and field observations show that when multiphase flow is taken into account, fracturing fluids with high retained permeabilities and premium high conductivity proppants can produce at as much as twice the gas production rate of fluids with 50% cleanup in gas wells producing as little as 10 barrels of water or condensate per MMCF. Using the developed criteria, proppants and fluids can be selected to optimize gas production from wells based upon prevailing reservoir conditions.

Abstract This paper describes the development and use of laboratory data to show the impact of multiphase non-Darcy flow upon gas production from hydraulic fractures. In the work, the impact of proppant type and fracturing fluid damage upon non-Darcy flow and effective conductivity vs. closure, temperature and gas/water/oil ratios is shown for sands, resin-coated sands and ceramics with various fracturing fluids. Laboratory derived correlations are then used to predict gas productivity and economics under various conditions of multiphase non-Darcy flow and the predictions are compared to field examples. The results of the testing show that multiphase non-Darcy flow dramatically increases the difference between the effective conductivities of various proppants at high closures. The laboratory data and field observations show that when this is taken into account, a premium proppant can show twice the production rate of commonly used sand products at high closures in gas wells producing as little as 10 barrels of water or condensate per MMCF. Introduction The subject of determining the conductivity of proppants at actual fracture conditions has been a subject of investigation for the last several years. The early work showed that the conductivity of proppant packs could be reduced by a factor of 10 if the impact of time, temperature and embedment are considered. An example of the long-term conductivity of 2 lb/ft2 20/40 proppants is shown in Figure 1. Clearly, the conductivity for common products can span at least from 200 md-ft to 5000 md-ft at 2 lb/ft2 at 8000 psi closure, which is common in deep hot reservoirs. These values can then be further discounted by the residual damage caused by the fracturing fluids, which can be from 10 to 90%. Even at these discounted values, the conductivity of the pack is sufficient for sand under laminar flow conditions to produce low permeability reservoirs. However, the impact of non-Darcy flow and multiphase flow are mistakenly not considered in many analyses, because they are not widely understood. Non-Darcy flow has a dramatic impact upon the effective permeability of proppant packs. Forcheimer was the first to modify Darcy's law to account for the increases in pressure observed beyond the predicted amount. Cornell and Katz in 1953 then put forth the common equation used today in which (1) where dP/L is the pressure drop per unit length, k is the absolute Darcy permeability, is the density, and is beta factor or the coefficient of inertial resistance. Cooke in 1973 performed a series of single phase experiments on various proppants vs. closure and rate to derive the relationship (2) in which the term 'a' is the intercept and 'b' the slope of a log- log plot of beta vs. permeability. The terms 'a' and 'b' depend upon the proppant type and size. This equation is used today in many production simulators to predict the impact of non-Darcy flow, Cooke together with Holditch adopted the units of atm-sec2/g, which is derived from the Darcy. The Holditch and Morse4 work showed the impact of the beta upon gas well productivity. P. 437

Abstract A method of drilling damage removal is presented which uses biologically generated acid (BGA) as the stimulation fluid. The BGA solution is not reactive during the actual pumping stage which allows its displacement into the reservoir to be controlled by the relatively low permeability of the near wellbore damage. Catalytic generation of acid occurs at a controlled rate once the BGA has been injected into the formation and results in uniform damage removal around the near wellbore region. The ability of BGA to be generated under a variety of temperature and pressure conditions and the compatibility evaluation of BGA with a variety of commonly used oil and water based drilling muds is first presented to establish some of the operational guidelines for BGA use. Drilling damage removal studies utilizing the modified API linear conductivity flow cell and carbonate material with BGA is presented to demonstrate the effectiveness of this stimulation fluid. Dual core flow test data is then presented which shows BGA's ability and HCL's inability to remove drilling damage over long horizontal intervals in carbonate formations. Introduction The introduction of acid to remove formation damage was first introduced to the petroleum industry by Frasch in 1895. There have been significant improvements over the past few years in recognizing and describing the various types of formation damage, and many publications have appeared on the subject. Formation damage resulting from drilling, cementing, completion/workover, gravel pack, production, and stimulation operations have been reported and reviewed recently. The removal of drilling fluid damage across producing intervals of oil and gas wells is required for production optimization. In general, the damage is removed through injection of acid as a stimulation fluid. The most commonly used acid for drilling damage removal in carbonate reservoirs is hydrochloric acid. Hydrochloric acid (HCL) has been used with success in conjunction with a variety of diversion techniques and coiled tubing in wells with relatively short production intervals. However, the difficulty of applying HCL in extremely long horizontal producing intervals to uniformly remove drilling damage has been identified by several operators as a very serious problem with the result being disappointing well productivity. P. 465

Over the past several years, the Intl. Standards Organization (ISO) and the American Petroleum Inst. (API) have been working to revise inter-national standards for proppant testing. The two ISO committees drafting standards for the petroleum industry are Technical Committee 28—Petroleum Products and Lubricants and Technical Committee 67—Materials, Equipment, and Offshore Structures for the Petroleum and Natural Gas Industry. Subcommittees are examining standards in drilling fluids, cementing, and completion fluids and materials. The first task of the fluids group was to rewrite API Recommended Practice 39, which was published in 2000 as ISO 13503-1 and API 13 M and titled Procedures for Measuring the Viscosity of Completion Fluids. The group, chaired by Mahmoud Asadi of Core Laboratories, is also writing standards for fluid-leakoff measurements, regained permeability tests, and friction tests. The second task has been to review API recommended practices for proppant materials. Three proppant subgroups have been set up to work on specific areas including quality-control testing procedures for proppants, proppant specifications, and proppant-conductivity testing. The work groups are well represented internationally, with participation from Brazil, China, France, Indonesia, Italy, Norway, The Netherlands, Poland, Russia, the United Kingdom, and the United States. Membership includes oil and gas producers, service companies, and proppant suppliers. Updating Recommended Practices API recommended practices for testing proppants were last published in 1995. A subgroup, chaired by Sara Joyce of Badger Mining, began reviewing the practices in 1998, and a committee draft was approved in 2000 that combined the API recommended practice documents into a single standard for testing proppant agents and gravel-pack materials. The work now has progressed to the draft international standard stage. The final draft will be circulated for voting in early 2006 with publication later in the year. Another subgroup, chaired by Mark Ziegler of Unimin Corp., is preparing a draft and conducting tests to set specifications for propping agents and gravel-pack materials. This draft will be circulated for voting as a draft international standard in 2006, with publication scheduled for 2007. In 2003, a third subgroup was formed to write procedures for measuring the long-term conductivity of proppant packs, chaired by Phil Kaufman of BJ Services. A committee draft was submitted in 2004 and is intended to replace RP 61, Recommended Practices for Evaluating Short-Term Proppant Pack Conductivity, published in 1989. A dozen facilities worldwide currently are running long-term conductivity tests without a standard procedure. The subgroup decided not to review and rewrite short-term conductivity procedures but instead to standardize procedures for measuring long-term conductivity. Recent advances in technology have been incorporated into these procedures to increase the accuracy of results and to standardize equipment. The conductivity document has progressed to draft international standard voting. After the comments are considered, the document will be submitted as a final draft for voting by early 2006, and it is scheduled for publication in 2007.

Summary The effects of capillary pressure, wettability, and relative permeability in controlling load water recovery following hydraulic-fracturing treatments have been examined. Laboratory studies have indicated that the alteration of wettability to control capillary pressure and/or relative permeability can promote a rapid, thorough cleanup of injected water. Field applications of these concepts have resulted in enhanced load water recoveries and higher production because of longer effective fracture lengths and/or higher effective fracture conductivities after treatment cleanup.

Summary The effects of downhole environmental conditions on fracturing-fluid rheology and leakoff were evaluated in a flow loop at simulated fracture conditions. Linear and crosslinked gel fluids were subjected to shear rates of 50 to 100 seconds−1 past core for 4 hours at temperatures of 75 to 250°F [24 to 121°C]. Nonlinear effects commonly observed with crosslinked gel fluids diminished as the fluid was sheared. Shearing for 30 minutes to 4 hours at 100 seconds−1 before a fluid-loss test was run resulted in leakoff following square-root-of-time behavior. Spurt loss increased for crosslinked gel fluids as the fluid degraded, whether by enzyme or oxidative mechanism. The leakoff coefficient decreased slightly with time under shearing conditions. Although the polymer was breaking, the absolute amount of polymer available for deposition did not change. The apparent viscosity of fluid remaining within the fracture was also investigated. During initial fluid leakoff, polymer was concentrated as a gel filter cake at the fracture face. Once an equilibrium filter-cake thickness was achieved, however, fluid loss to the formation resulted in an increase in the polymer concentration in the remaining fluid and hence an increase in apparent viscosity.

Summary This work examines the variability in fluid leakoff rates measured under static and dynamic conditions. Laboratory-generated-data are compared to field-measureddata, and the conditions under which static and dynamic data should be used for fracture design are examined. Control of fluid leakoff in both the low-permeability matrix and highly permeable natural fractures is examined on formation cores under a variety of conditions. The control mechanism offered by various fluid-loss additives isevaluated by examining the fluid-matrix and fluid-filter-cake interactions. Introduction Fluid leakoff during hydraulic fracturing can exceed 70%of the injected volume if not controlled properly. A consequence of high leakoff can be the severe curtailment of production because of formation matrix damage, adverse formation fluid interactions, or altered fracturegeometry. An overwhelming amount of fluid can berequired to achieve a desired fracture geometry in a massive hydraulic fracturing treatment; thus, fluid efficiency cangovern the economic success of the treatment. A knowledge of the leakoff characteristics of aparticular formation is essential both to select proper fluid particular formation is essential both to select proper fluid loss control measures for the treatment and to predictfracture geometry. Advances in pressure analysis have made possible theestimation of formation fluid-leakoff rates from pressuredecline following injection. The method depends ona knowledge of gross fracture height; therefore, the method is best applied in formations with a large net permeable height. Using changes in fracture gradient to permeable height. Using changes in fracture gradient to estimate leakoff rates during pumping has been proposedrecently. Leakoff rates obtained from field measurements areimportant not only because they provide realistic numbersfor the prediction of fracture geometry and job design, but also because they provide a yardstick for laboratory measurements of leakoff and the development of fluid-loss control methods and additives. When such field data are not available, laboratory wall-building coefficient (C.) and spurt data are generated by applying the fluid in question to formation core samples. The conditions under which these tests are run candictate the resulting leakoff coefficient. Apart from effortsto simulate actual pumping conditions, wide variations canresult from simple static testing procedures. In the workdescribed herein, several factors affecting the outcomeof fluid-loss tests have been identified. Once those factors are controlled satisfactorily, various dynamic methodsof testing are compared. An attempt is made to correlate field-measured leak offdata with laboratory results. Both field and laboratory datashow the overriding influence of leakoff to natural fractures and/or high-permeability streaks. Once the highleakoff to these areas is curbed, leakoff to thelow-permeability matrix is influenced strongly by the shearrate within the fracture, particularly in high-rate jobs inthe early part of the pad where fracture widths arerelatively small. This can lead to changing leakoff ratesthroughout the treatment. To account for variations in C, during a treatment, Crawford 4 suggests multiplyinglaboratory values by a factor of. Characteristics of a particular formation can dictate the fluid-loss additive or combination of additives required to achieve necessary leakoff control. Particulate additivesare essential in controlling leakoff to high-permeability streaks or formations, while liquid hydrocarbon additives function well in low-permeability matrix control. The interaction of each of these additives with the formation and filter cake affects their performance. This work looks indetail at the interaction of hydrocarbon with complexed fluids and low-permeability formations. Discussion The leakoff rate during a hydraulic fracturing treatmenthas a marked effect on the final geometry of the fracture. With higher-efficiency fluids, less fluid is required toachieve a desired fracture length. For example, when thefracture is contained within zone, decreasing C., from0.001 to 0.0001 ft/min 1/2 [0.03 to 0.003 cm/min 1/2]increases the efficiency from 30 to 90%, and makes itpossible to use one-third as much fluid to achieve a desired possible to use one-third as much fluid to achieve a desired fracture length (Fig. 1). Using the same example, increasing fracturing fluidefficiency also increases closure time (Fig. 2). Ninety-percent fluid efficiencies alone become impractical, sinceit is desirable for the fracture to close on the proppantbefore gel degradation to minimize proppant settling. Ina large number of fracture treatments, where the fluidstability and/or break rate is tailored to 12 to 24 hours, fluid efficiencies of no greater than 70% are advisable. JPT P. 1071

A series of N alpha-1-(dimethylamino)-5-naphthalenesfulfonyl (dansyl) derivatives of peptidyl chloromethanes (chloromethyl ketones) were synthesized and employed to introduce the fluorescent dansyl moiety specifically into the active sites of proteinases via affinity labeling. Dansylalanyllysychloromethane (DALCM) was utilized to inactivate and fluorescently label trypsin and the trypsin-like enzyme thrombin. Dansylleucylphenylalanylchloromethane (DLPCM) was synthesized and selectively employed as an inhibitor of chymotrypsin. The di-, tri-, and tetrapeptides--dansylprolylalanylchloromethane (DPACM), dansylalanylprolylalanylchloromethane (DAPACM), and dansylprolylalanylprolylalanylchloromethane (DPAPACM)--were synthesizedand their interaction with elastase was evaluated. The compounds DALCM, DLPCM, and DAPACM all proved to be effective, fast-acting proteinase inhibitors. Studies of energy transfer in the enzyme-inhibitor conjugates led to results entirely consistent with the proposed conformational bomology of thrombin with the other serine proteinases studied. The fluorescent affinity labels are believed to posses enormous potential for the localization, isolation, and characterization of enzymes.

Summary Fluid loss under dynamic conditions, considering such realistic conditions as low-permeability core samples and extreme shear conditions, has been examined and is reported in this paper. Dynamic data of fluid loss as a function of time, pressure, and temperature have been developed.

Abstract The roles of capillary pressure, wettability and relative permeability in controlling load water recovery following hydraulic fracturing treatments have been examined. It has been found in laboratory studies that the judicious alteration of wettability to control capillary pressure and/or relative permeability can promote a rapid thorough cleanup of permeability can promote a rapid thorough cleanup of injected water. Field applications employing these concepts have resulted in enhanced load water recoveries and higher production due to longer effective frac lengths and/or higher fracture conductivities following cleanup. Introduction Aqueous treating fluids have traditionally been very attractive in hydraulic fracturing treatments. As many as 90% of the fracturing treatments performed today are carried out with water-based performed today are carried out with water-based fluids. The attractiveness of water is due to its low cost and safety compared to hydrocarbon or alcohol based fluids. Furthermore, the chemistry involved in providing a wide variety of predictable fluid properties is much better understood. From a compatibility standpoint, however, the injection of water into a hydrocarbon bearing formation may impair production via formation damage or the retention of water following the treatment. Several chemical additives have been developed to enhance formation compatibility of aqueous fluids. Clay stabilizers to prevent clay swelling and migration, iron and paraffin controls additives, nonemulsifiers, and surface tension reducing agents are routinely incorporated into aqueous fracturing fluids. Even after employing these measures, the problem of load water retention often remains. It is not uncommon to recover as little as 10 to 15% of the load water following a hydraulic fracturing treatment of a tight, gas bearing formation. The impact of water retention on hydrocarbon production has been discussed by several production has been discussed by several investigators. It has been noted that production in tight low pressure gas wells can production in tight low pressure gas wells can completely blocked if the drawdown pressured exceed the capillary pressure of injected water trapped near the fracture faces. Should permeability to hydrocarbon be established in the permeability to hydrocarbon be established in the invaded zone, the existing high water saturation can depress productivity for extended periods. Productivity will increase only as the periods. Productivity will increase only as the water is gradually removed. This work examines the roles of capillary pressure, wettability, and relative permeability in pressure, wettability, and relative permeability in controlling load water recovery. It has been found that the judicious alteration of wettability to control capillary pressure and/or relative permeability can promote a rapid, thorough cleanup permeability can promote a rapid, thorough cleanup of injected aqueous fracturing fluids. Field applications employing these concepts have shown enhanced load water recoveries and higher production due to longer initial effective frac lengths production due to longer initial effective frac lengths and higher fracture conductivities following cleanup. Discussion During a hydraulic fracturing treatment injection pressure and imbibition combine to create an area of essentially 100% water saturation near the fracture face. The effectiveness of drawdown and/or return hydrocarbon flow in displacing the injected water depends directly on the magnitude of the capillary end effects in a gas well and on the wettability when producing oil. The factors influencing load recovery and production in gas and oil wells will be considered separately. Gas Well Cleanup The role of capillary pressure in controlling load recovery from a gas well can be demonstrated with the two phase simulator GAS. WAT. Given the low permeability gas well conditions listed in Table 1, it can be calculated that a maximum of 10% of the injected water will be returned within 7 days at a capillary pressure of 250 psi with no further cleanup. On the other hand, lowering the capillary pressure to zero results in 50% load recovery within 14 days with continued cleanup beyond that point (Figure 1).

An effective fluid loss control measure that has recently found application in the hydraulic fracturing of gas wells is the addition of an immiscible hydrocarbon phase to aqueous fracturing fluids. In this work the effectiveness and regained permeabilities after employing hydrocarbon and common particulates are assessed. Laboratory studies indicate that reduced hydrocarbon concentrations (