Water-based Fracturing Fluids Research Articles

Simulation of hydraulic fracturing with propane-based fluid using a fracture propagation model coupled with multiphase flow simulation in the Cooper Basin, South Australia

In many unconventional reservoirs, gas wells do not perform to their potential when water-based fracturing fluids are used for treatments. The sub-optimal fracture productivity can be attributed to many factors such as effective fracture length loss, low load fluid recovery, flowback time, and water availability. The development of unconventional reservoirs has, therefore, prompted the industry to reconsider waterless fracturing treatments as viable alternatives to water-based fracturing fluids. In this paper, a simulation approach was used by coupling a fracture propagation model with a multiphase flow model. The Toolachee Formation is a tight sand in the Cooper Basin, around 7,200 ft in depth, and has been targeted for gas production. In this study, a 3D hydraulic fracture propagation model was first developed to provide fracture dimensions and conductivity. Then, from an offset well injection fall off test, the model was tuned by using different calibration parameters such as fracture gradient and closure pressure to validate the model. Finally, fracture propagation model outputs were used as the inputs for multiphase flow reservoir simulation. A large number of cases were simulated based on different fraccing fluids and the concept of permeability jail to represent several water-induced damage effects. It was found that LPG was a successful treatment, especially in a reservoir where the authors suspected the presence of permeability jails. The authors also observed that total flowback recovery approached 76% within 60 days in the case of using gelled LPG. Modelling predictions also support the need for high-quality foam, and LPG can be expected to bring long-term productivity gains in normal tight gas relative permeability behaviour.

Development of new testing procedures to measure propped fracture conductivity considering water damage in clay-rich shale reservoirs: An example of the Barnett Shale

Multi-stage hydraulic fracturing is the key to the success of many shale gas and shale oil reservoirs. The main objective of hydraulic fracturing in shale is to create fracture networks with sufficient fracture conductivity. Due to the variation in shale mineralogical and mechanical properties, fracture conductivity damage mechanisms in shale formations are complex. Standard fracture conductivity measurement procedures developed for fractures with high proppant concentration had to be modified to measure the conductivity in fractures with low proppant concentration. Water-based fracturing fluids can interact with the clay minerals in shale and eventually impact shale fracture conductivity. All these challenges require more experimental studies to improve our understanding of realistic fracture conductivity in shale formations. The aims of this work were to design an experimental framework to measure fracture conductivity created by low concentration proppants and to investigate the mechanisms of conductivity damage by water. We first presented the laboratory procedures and experimental design that can accurately measure fracture conductivity of shale fractures at low concentrations of proppants. Then we measured the undamaged shale fracture conductivity by dry nitrogen. Water with similar flowback water compositions was injected to simulate the damage process followed by secondary gas flow to measure the recovered fracture conductivity after the water damage. This study shows that the developed laboratory procedures can be utilized to reproducibly measure shale fracture conductivity by both gas and liquid. The conductivity measurement of propped fractures by small size proppants at low concentrations requires strict control on gas flow bypassing the fracture both parallel and perpendicular to the fracture length direction. Shale fracture surface softening is identified as the dominant cause for the significant conductivity reduction after water flow.

Experimental investigation of shale imbibition capacity and the factors influencing loss of hydraulic fracturing fluids

Spontaneous imbibition of water-based fracturing fluids into the shale matrix is considered to be the main mechanism responsible for the high volume of water loss during the flowback period. Understanding the matrix imbibition capacity and rate helps to determine the fracturing fluid volume, optimize the flowback design, and to analyze the influences on the production of shale gas. Imbibition experiments were conducted on shale samples from the Sichuan Basin, and some tight sandstone samples from the Ordos Basin. Tight volcanic samples from the Songliao Basin were also investigated for comparison. The effects of porosity, clay minerals, surfactants, and KCl solutions on the matrix imbibition capacity and rate were systematically investigated. The results show that the imbibition characteristic of tight rocks can be characterized by the imbibition curve shape, the imbibition capacity, the imbibition rate, and the diffusion rate. The driving forces of water imbibition are the capillary pressure and the clay absorption force. For the tight rocks with low clay contents, the imbibition capacity and rate are positively correlated with the porosity. For tight rocks with high clay content, the type and content of clay minerals are the most important factors affecting the imbibition capacity. The imbibed water volume normalized by the porosity increases with an increasing total clay content. Smectite and illite/smectite tend to greatly enhance the water imbibition capacity. Furthermore, clay-rich tight rocks can imbibe a volume of water greater than their measured pore volume. The average ratio of the imbibed water volume to the pore volume is approximately 1.1 in the Niutitang shale, 1.9 in the Lujiaping shale, 2.8 in the Longmaxi shale, and 4.0 in the Yingcheng volcanic rock, and this ratio can be regarded as a parameter that indicates the influence of clay. In addition, surfactants can change the imbibition capacity due to alteration of the capillary pressure and wettability. A 10 wt% KCl solution can inhibit clay absorption to reduce the imbibition capacity.

Rheology of polymer-free foam fracturing fluids

Aqueous polymeric solutions are commonly used for fracturing in conventional petroleum reservoirs for their ability to transport proppants deep into fractures, but such fluids are not used for shale reservoirs because of the plugging of nano-pores of shales by large polymer molecules. Polymer-free aqueous foams can be used in shale fracturing because of their capacity to suspend proppants and lower water consumption than commonly used water-based fracturing fluids. In this work, the rheology of three kinds of polymer-free foams (A: 0.5 wt% regular anionic surfactant, B: Fluid A+2 wt% glycerol, C: 0.5 wt% viscoelastic surfactant or VES) are studied in a recirculating pipe rheometer up to 155 °F and 2000 psi. These temperature and pressure conditions are lower than those for typical shales of current interest. All three foams exhibit power-law rheological behavior. The regular surfactant foams (A and B) show shear thinning behavior at qualities above 60%, non-shear dependent behavior from 50% to 60% and shear thickening below 50% (due to turbulence). The VES foams show shear thinning at qualities less than 60%. Temperature lowers the viscosity of foams by decreasing the liquid phase viscosity and the stability of the bubbles, but the temperature effect is small for foams A and B. Pressure increases foam viscosity; the increase is higher for higher quality foams. As the pressure increases, the rate of viscosity increase decreases. The aqueous foams A and B are both less viscous than typical guar foams (0.24 wt% polymer), while the VES foam C has a similar viscosity. The model proposed by Brouwers (2010) for suspensions agrees the best with the measured data for quality under 60%; the model proposed by Princen and Kiss (1989) for high quality does not match the experimental data. New correlations have been developed to describe the aqueous foam rheology as a function of shear rate, quality, and pressure at the parameter range typical of hydraulic fracturing. The correlations can be incorporated in a fracture propagation simulator to evaluate the foam fracturing efficiency.

A Critical Review of Hydraulic-Fracturing Fluids for Moderate- to Ultralow-Permeability Formations Over the Last Decade

Summary Hydraulic fracturing is a well-established process to enhance productivity of oil and gas wells. Fluids are used in fracture initiation and the subsequent proppant and/or sand transport. Several chemistries exist for these fluids. This paper summarizes the published literature over the last decade (more than 100 technical articles) and captures the advances in the design of water-based fracturing fluids for fracturing ultralow- to moderate-permeability reservoirs (nonfrac-pack applications). Guar-based polymers are still being used in fracturing operations for wells at temperatures of less than 300°F (148.9°C). To minimize the damage associated with this class of polymers, the industry has attempted several approaches. These included the use of a lower polymer concentration in formulating these fluids and alteration of the crosslinker chemistry so that one can generate higher viscosity values with lower polymer loadings. Moreover, the industry shifted toward the use of cleaner guar-based polymers because commercial guar contains a minimum of 5 wt% of residues, which can cause damage to proppant packs. The review has also revealed that shear and pressure effects on the rheological behavior of borate-crosslinked gels is significant. Although these fluids recover their viscosity after shear, they have been observed to lose a significant portion of their viscosity under high pressures. When fracturing deeper wells in hotter reservoirs, the need arose for a new class of thermally stable polymers. Thus, the industry shifted toward polyacrylamide- (PAM-) based polymers. These synthetic polymers offer sufficient viscosity at temperatures up to 450°F (232°C). Examples include 2-acrylamido-2-methyl-propanesulfonic acid (AMPS) and copolymers of partially hydrolyzed PAM-AMPS-vinyl phosphonate. To address the challenge of high-pressure pumping requirements on the surface, high-density brines have been used to increase the hydrostatic pressure by 30%. Breakers’ chemistry has seen introduction of new materials. These breakers decrosslink the gel by reacting with the crosslinker. They form ligands with the metallic crosslinkers and displace them from the crosslinking bonds with the guar-based polymers. Examples of these breakers include polysuccinimides and lignosulfonates. To minimize the environmental impact of using massive amounts of fresh water and to minimize costs associated with treating produced water, the use of produced water in hydraulic-fracturing treatments has been reported. In addition, the paper captures the advancements in the use of slickwater, which uses drag-reducing agents (PAM-based polymers) to minimize friction. The paper highlights the first use of breakers that were introduced to improve the cleanup of these drag reducers. For foamed fluids, new viscoelastic surfactants that are compatible with carbon dioxide are discussed. The paper also sheds light on the use of emerging technologies, such as nanotechnology, in the design of new, efficient hydraulic-fracturing fluids. For example, nanolatex silica was used to reduce the concentration of boron found in conventional crosslinkers. Another advancement in nanotechnology was the use of 20-nm silica particles suspended in guar gels. The paper provides a thorough review of all these advancements.

A Review of Shale Gas Exploitation Technology

The United States has taken the lead to achieve the shale gas industrial production and created a shale gas revolution throughout the world. According to the exploitation experience of the United States, the key of shale gas business development realization is to adopt horizontal well combined with fracturing technology. At present fracturing technology used commonly include multi-stage fracturing, water fracturing, refracturing, etc. China has great potential in shale gas resource, recoverable resources has 25.08×1012m3, but they are mainly located in the drought and water lack area, and the clay mineral content for shale gas reservoir is higher, the traditional water-based fracturing fluid used for shale gas development caused a lot of water consumption and serious reservoir damage, therefore, it is not suitable for shale gas reservoir conditions in China. In the process of domestic shale gas development, exploring novel fracturing and development technology is irreversible.

Experimental Investigation of Fracturing-Fluid Migration Caused by Spontaneous Imbibition in Fractured Low-Permeability Sands

SummaryDuring hydraulic-fracturing operations in low-permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix is believed to have a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may affect the post-fracturing productivity of the well. However, there is lack of direct experimental and visual evidence of the extent of fluid retention, evolution of the resulting imbibing-fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leakoff is monitored as a function of space and time by use of X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low-permeability formations (5 to 10 md) to show strong capillary forces because of their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in low-permeability sands. The relevance of capillarity as a driver of fluid migration and retention in a low-permeability sand sample is interpreted visually and quantified and compared with high-permeability Berea sandstone in our experiments. It is seen that although low-permeability sands are subject to strong capillary forces, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. Nevertheless, saturation values attained as a result of spontaneous imbibition are comparable with those obtained for high-permeability samples. Leakoff of fracturing fluids during the shut-in period of a well can result in delayed gas flowback and can hinder gas production. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently affecting the post-fracturing productivity of the well.

Investigation of gas flow hindrance due to fracturing fluid leakoff in low permeability sandstones

Hydraulic fracturing has become a necessary practice in order to attain economical gas flow rates from low permeability formations. During and immediately following the creation of a fracture, high injection pressures cause fracturing fluid to leak off into the adjacent matrix. This work focuses on the impact of fracturing fluid leak off on gas flow through tight formations as a function of leakoff volume and shut-in time.It was observed that an increase in leakoff volume reduces effective permeability to gas while an increase in shut-in time increases it. Gas flow hindrance caused by the leak off of water-based fracturing fluid is mitigated by shut-in time in that it favors spontaneous redistribution of the fluid deeper into the rock matrix. However, results from this work demonstrate that the flow hindrance caused by the initial leak off is superior to the effective permeability gains by shut-in time. This imbalance highlights a key determining factor behind gas flow hindrance due to fracturing fluid leak off – fluid saturation in the neighborhood of the fracture.The properties of the formation were found to also play a significant role in determining regained permeability. Lower formation permeability slows improvements to gas flow due to lower mobility of the invading fluid despite expected higher capillarity. Furthermore, the extension of these observations to rock formations with lower permeability, such as tight sand and shale, suggests that shut-in time may have an insignificant impact on regained permeability improvement in systems with depressed relative permeability curves.Leakoff volume and shut-in time are variables that work differently to dictate saturation distribution in the neighborhood of the fracture. Saturation within the invaded zone and characteristics of the formation's relative permeability curve may be the key determinants of gas flow hindrance following hydraulic fracturing activities. This may explain the lack of trends in the field – conditions vary between formations.

Experimental Method to Simulate Coal Fines Migration and Coal Fines Aggregation Prevention in the Hydraulic Fracture

A simple and effective experimental method is proposed to simulate coal fines migration through the proppant pack; such migration inevitably occurs during the process of fracturing fluid flowback or dewatering and gas production in coalbed methane (CBM) reservoirs. The damage to conductivity caused by coal fines migration in the pack and the factors affecting such migration are analyzed. A dispersion agent of coal fines applicable to hydraulic fracturing in CBM is optimized, consequently solving the problem of coal fines aggregation and retention in the proppant pack. Discharging coal fines with water or water-based fracturing fluid from the proppant pack can be difficult because of the adsorption and hydrophobicity of coal fines. Thus, coal fines are likely to aggregate and be retained in the proppant pack, thereby resulting in pore throat plugging, which causes serious damage to fracture conductivity. Two percent coal fines can reduce propped fracture conductivity by 24.4 %. The mobility and retention of coal fines in the proppant pack are affected by proppant size, proppant type, flowback rate, and coal fines property. When flowback rate exceeds the critical value, coal fines can be discharged from the pack, consequently reducing damage to propped fracture conductivity. More importantly, the steady discharging of coal fines requires steady dewatering and gas production to avoid flow shock, which causes pressure disturbance to drive coal fines in a remote formation. The optimized dispersant FSJ-02 employed in this paper can effectively change the wettability and surface potential of coal fines to improve their suspension and dispersion in water-based fracturing fluid. The recovery rate of coal fines increased by 31.5 %, whereas conductivity increased by 13.3 %.

Laboratory Study and Evaluation on a Novel Clearfrac Fluid System

Hydraulic fracturing is an effective measure to recover the permeabilityof reservoir and important to enhance oil and gas well production and water injection well. Fracturing fluid is the key factor in the fracture treatments. At present, water-based fracturing fluids are popular, because of low costs and steady performance, which has the largest applications. However, it performs badly in residue. The novel developed clearfrac fluid system named CF1 has lowresidue, cost affectivity, prior temperature resistance properties. Evaluation through a series of lab experiments, the experiments result show that the novel clearfrac fluid system can satisfy with the requirement of low damage and have favorable temperature resistance under 120 。C. The damage to the core matrix due to with the broken frac-fluid is low. Prior properties of the novel clear-fracturing fluid are suitable to high temperature and high pressure reservoirs. It is also a novel environmental friendly viscoelastic surfactant fracturing fluid. The development of the novel clear-fracturing fluid for hydraulic fracturing industry is significant.

Montney Fracturing-Fluid Considerations

Summary The Montney gas reservoir has become a critically important component of current western Canadian gas supply and offers exciting future potential. However, this reservoir often presents variable and unique stimulation challenges. Unlike reservoirs that display little water sensitivity, such as the U.S. Barnett Shale and possibly the Muskwa in the Northeastern British Columbia Horn River Basin, recovery of water-based fluids in the Montney can be a key consideration in achieving economic production rates. The use of water-based fracturing fluids in low-permeability reservoirs can result in loss of effective frac half-length caused by phase trapping associated with the retention of the introduced water-based fluid to the formation. This problem is increased by the water-wet nature of most tight-gas reservoirs (where no initial liquid-hydrocarbon saturation is or ever has been present) because of the strong spreading coefficient of water in such a situation. The retention of increased water saturation (Sw) in the pore system after the injection of water-based completion fluids can restrict the flow of produced gaseous hydrocarbons, such as methane. Capillary pressures of 10 MPa-20 MPa, or much higher, can be present in low-permeability formations at low-water saturation levels. Inability to generate sufficient capillary-drawdown force using the natural reservoir-drawdown pressure can result in extended fluid-recovery times or permanent loss of effective fracture half-length. Furthermore, use of water in subnormally saturated reservoirs, where much of the connate water has been removed by long-term evaporation effects associated with gas migration, might also reduce permeability and associated gas flow through a permanent increase in Sw of the reservoir. Secondary costs, such as rig time for swabbing, can add to the negative economic impact. The Montney is found to be a dry-gas reservoir in some areas, transitioning to an oil reservoir in other areas. Because of this, it would not be surprising to encounter retrograde condensate production through transition areas. In such a case, if sufficient drawdown pressure is applied to reduce reservoir pressure below the dewpoint, liquid hydrocarbons might condense from the produced gas phase, resulting in two-phase flow and potential trapping of the hydrocarbon liquid phase. Also, some areas of the upper Montney exhibit reservoir pressures in the 30 MPa range, whereas other areas exhibit lower pressures in the 17 MPa-21MPa range. The same drawdown on a lower-pressured reservoir could therefore result in condensate condensing from the gas phase, where it would not have in the higher-pressured reservoir. If a third aqueous fracturing fluid is introduced, three-phase flow might occur. The resulting reduced relative permeability to gas might drastically reduce production rates. Also, emulsion-formation potential exists, which could present an additional reduction in fluid flow and recovery. Choice of fracturing fluid must be carefully determined for each area of the Montney, balancing economics with production. It is important to always keep in mind that key reservoir properties can vary dramatically in the Montney, as a function of both geographic location and depth. This paper presents laboratory test results of regained methane permeability vs. drawdown pressure and contact time with Montney core under representative reservoir conditions. Water, foamed water and hydrocarbon-based fracturing fluid systems are evaluated. The testing was funded by and arranged for by operators in preparation for actual fracturing treatments in two different fields. Core plugs, time and funding were limited; therefore, only tests deemed necessary for decision-making were run. Limited repeat testing was therefore possible.

Fluid Selection for Energized Hydraulic Fractures

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124361, ’Fluid Selection for Energized Hydraulic Fractures,’ by Kyle E. Friehauf and Mukul M. Sharma, SPE, University of Texas at Austin, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 4-7 October. Traditional hydraulic-fracture simulators do not take into account the compositional, thermal, and phase-behavior effects that are crucial to the success of energized fractures. Traditional water-based fracturing fluids are not ideally suited for use in tight, depleted, or water-sensitive formations. Gas-energized fracturing fluid addresses the water-trapping problem by creating a high gas saturation in the invaded zone, thereby facilitating gas flowback. A fully compositional fracture simulator was used to evaluate different designs for energized fractures. It showed that energized fluids should be applied to rocks when the drawdown pressure is insufficient to remove the liquid. Use of a compositional fracture simulator allows systematic design of energized-fracture treatments. Introduction A hydraulic-fracturing process becomes energized with the addition of a compressible, sometimes soluble, gas component into the treatment fluid. Energizing the fluid creates a high gas saturation in the invaded zone, thereby facilitating gas flowback. It is estimated that one-third of the fractures pumped in the US are energized by a gaseous phase. Energized-fluid fracturing is common in reservoirs that are water sensitive or that have a low pore pressure or low permeability. In conducting this study, the hydraulic-fracturing model used compositional and energy balances and coupled them with phase behavior, making this model applicable to energized fluids. The productivity-index (PI) -ratio values were calculated with a PI model that takes into account varying fracture conductivity and the damage around the fracture face caused by fluid invasion. Multiphase-Fracturing-Fluid Properties As with all fluids, the properties of an energized fracturing fluid depend on fluid composition and the range of conditions under which the fluid is applied. Commonly, CO2 or N2 are added to a traditional water-based fluid to energize the fluid. This paper focused on these fluid systems because they are used most often and because their rheology has been studied to a great extent, but methanol is another possible component. This paper discusses commonly used fluid systems containing the following component mixtures: CO2/H2O, N2/H2O, and CO2/methanol/H2O.

Optimum Hydrocarbon Fluid Composition for Use in CO2 Miscible Hydrocarbon Fracturing Fluids and Methods of Core Evaluation

Abstract Previous studies(1–4) described the theory and application of CO2 miscible hydrocarbon fracturing fluids for gas well stimulation. These fluids are ideally suited to gas reservoirs susceptible to phase trapping resulting from high capillary pressures when water-based fluids are used. Gas reservoirs particularly prone to phase trapping are those with in situ permeability less than 0.1 mD, those with initial water saturations less than what would be expected from normal capillary equilibrium (subnormally water saturated) and those that are under pressured. Such reservoirs represent a growing proportion of the market. This, combined with increased gas prices, creates a strong need for an optimized gas well fracturing fluid system. Hydrocarbon-based fracturing fluids present an ideal solution to phase trapping concerns associated with water-based fluids provided the hydrocarbon fluid can be effectively and quickly removed from the formation after the fracturing treatment. This paper investigates in more depth what constitutes an ideal hydrocarbon-base oil for this application. This involves consideration of many factors including cleanup mechanisms, safety, cost and capability to be gelled and broken. In order to meaningfully evaluate fluid clean up, regained core permeability evaluations must be conducted by accurately duplicating downhole conditions. This paper presents testing methodologies designed to achieve this goal. To illustrate the need for these methodologies, the applicable phase behaviour and fluid displacement mechanisms by which these fluid systems operate are discussed. Topics covered will include:Methane drive fluid recovery mechanism involving the use of CO2 with hydrocarbons and resulting effect on interfacial tension (IFT).Secondary recovery mechanism based on vapour pressure of light hydrocarbons resulting in their being produced back in the gas phase with methane.Application of these concepts to address phase trapping in low-permeability gas reservoirs and how these effects are accentuated in formations that may be subnormally water-saturated, have low reservoir pressure or have low permeability.The need to simulate downhole conditions accurately to properly represent the recovery mechanisms. This includes duplication of temperature, pressure and fluid-loss mechanisms. Duplicating leakoff is the key to representative duplication of phenomena at the fracture face.Compare nitrogen to methane for reference and fluid recoveries and discuss why it is necessary to use methane to obtain proper simulation and modelling of the actual field performance of the fracture fluids.To illustrate fluid performance and demonstrate test methodologies, results of a regain permeability evaluation conducted with the optimum fluid and test methodologies discussed will be presented. It will be shown that in a formation known to be highly sensitive to water-based fluid retention (phase trapping), 100% regain permeability can be achieved at a minimal 140 kPa of applied drawdown pressure. Introduction The use of water-based fracturing fluids in low-permeability reservoirs may result in the loss of effective fracturing half length due to phase trapping effects associated with the retention of a large portion of the introduced water-based fluid in the formation.

Total Phosphorus Recovery in Flowback Fluids After Gelled Hydrocarbon Fracturing Fluid Treatments

Abstract A previous work(1) described refinery plugging caused by volatile phosphorus components originating from phosphate ester oil gellants. Also documented were two successful field trials of new phosphonate ester oil gellants shown to address this problem. Another paper(2) presented the results of additional field testing of phosphonate ester gellants directed at the optimization of cost and performance. A maximum of 0.5 ppm volatile phosphorus in crude specification has been proposed to address costly unplanned refinery shutdowns. This specification is based on what is considered achievable through a combination of new chemistry and typical field dilution. However, this specification is based on average concentrations of phosphorus added to the oil to gel it and assumes the oil is phosphorus free to begin with. In some flowback studies, total and resulting volatile phosphorus concentrations greatly in excess of that added have been observed. In addition, refinery plugging is more the result of total phosphorus throughput than peak concentrations at any one point. Therefore, an understanding of total phosphorus recovery in addition to peak concentrations is needed. The objectives of this paper are to study:Total percent recovery of phosphorus originally added as phosphorus based gellant;Total percent recovery of volatile phosphorus as a function of total phosphorus;Peak concentrations of total and volatile phosphorus;Phosphorus concentrations in new and reused fracturing fluids before the addition of gellants; and,Potential explanations for phosphorus concentrations significantly higher than those originally added, which include phosphorus removal resulting in a positive/negative initial mass balance and long-term phosphorus removal with respect to overall mass balance. Introduction Unconventional gas reservoirs, including tight gas, shale gas and coalbed methane, are becoming critically important components of current and future gas supply. These reservoirs often present unique stimulation challenges. The use of water-based fracturing fluids in low-permeability reservoirs may result in the loss of effective fracture half-length caused by phase trapping associated with the re-tention of the introduced water-based fluid into the formation. This problem is increased by the water-wet nature of most tight gas reservoirs (where no initial liquid hydrocarbon saturation is, or ever has been, present) because of the strong spreading coefficient of water in such a situation. The retention of this increased water saturation in the pore system can restrict the flow of produced gaseous hydrocarbons such as methane. Capillary pressures of 10 ? 20 MPa or higher per thousand can be present in low-permeability formations at low water-saturation levels. The inability to generate a sufficient capillary drawdown force using the natural reservoir drawdown pressure can result in extended fluid-recovery times or the permanent loss of effective fracture half-length. Furthermore, use of water in subnormally saturated reservoirs may also reduce permeability and associated gas flow through a permanent increase in water saturation of the reservoir. Secondary costs such as rig time for swabbing can add to the negative economic impact. The effects of fracturing fluid retention on gas flow in the fracture face can be as important a consideration as fracture conductivity when designing a treatment.

Liquid Petroleum Gas Fracturing Fluids for Unconventional Gas Reservoirs

Abstract Unconventional gas reservoirs, including tight gas, shale gas and coalbed methane, are becoming a critically important component of the current and future gas supply. However, these reservoirs often present unique stimulation challenges. The use of water-based fracturing fluids in low permeability reservoirs may result in loss of effective frac half-length caused by phase trapping associated with the retention of the introduced water into the formation. This problem is increased by the water-wet nature of most tight gas reservoirs (where no initial liquid hydrocarbon saturation is, or ever has been, present) because of the strong spreading coefficient of water in such a situation. The retention of increased water saturation in the pore system can restrict the flow of produced gaseous hydrocarbons such as methane. Capillary pressures of 10 to 20 MPa or higher can be present in low permeability formations at low water saturation levels. The inability to generate sufficient capillary drawdown force using the natural reservoir drawdown pressure can result in extended fluid recovery times, or permanent loss of effective fracture half-length. Furthermore, use of water in subnormally saturated reservoirs may also reduce permeability and associated gas flow through a permanent increase in water saturation of the reservoir. Secondary costs, such as rig time for swabbing, can add to the negative economic impact. Gelled liquid petroleum gas-based fracturing fluids are designed to address phase trapping concerns by replacement of water with a mixture of liquid petroleum gas (LPG) and a volatile hydrocarbon fluid. Once the well is drawn down for flowback, some of the LPG portion of the fluid may be produced back as a gas, dependent upon temperature and pressure. The remaining LPG remains dissolved in the hydrocarbon fluid and is produced back as a miscible mixture using a methane drive mechanism. By eliminating water and having LPG as up to 80 - 90% of the total fluid system, cleanup is greatly facilitated, even in wells having very low permeability and reservoir pressure. The effects of fracturing fluid retention on gas flow in the fracture face can be as important as fracture conductivity when designing a treatment. It is possible to have a conductive fracture with good half-length in the desired productive zone and still not realize economic or optimum gas production if phase trapping and/or relative permeability effects are restricting gas flow. Description Gelled LPG-based fracturing fluids are a unique hydrocarbon-based fracturing fluid system designed for gas well stimulation. They use up to 100% gelled LPG for the pad and flush. The sand slurry stages use a mixture of up to 90% LPG with the balance of the volume being a volatile hydrocarbon-based fluid. All chemicals and proppant are added to the base fluid at the blender. LPG, which composes the balance of the downhole fluid volume, is injected at the wellhead where it forms one miscible mixture with the base oil. It is important to note that under pumping pressures, this is a single-phase gelled fluid system, similar to gelled oil in rheology, friction pressures, proppant transport and leakoff control.

Leakoff Control and Fracturing-Fluid Cleanup in Appalachian Gas Reservoirs

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 98145, "Case Histories: Damage Prevention by Leakoff Control and Cleanup of Fracturing Fluids in Appalachian Gas Reservoirs," by J. Paktinat, SPE, J.A. Pinkhouse, SPE, and C. Williams, SPE, Universal Well Services Inc.; G.A. Clark, SPE, ConocoPhillips; and G.S. Penny, SPE, CESI Chemical, prepared for the 2006 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 15–17 February. Laboratory and field data collected in the studies detailed in the full-length paper illustrate that addition of a microemulsion (ME) to a fracturing fluid has significant advantages over conventional surfactant treatments when water recovery, increased effective fracture length, and well productivity are of concern to the operator. Introduction A continuing challenge in Appalachian basin gas wells is post-fracturing fluid recovery in low-pressure, low-permeability reservoirs. Most wells are stimulated with water-based fracturing fluids and produce back less than one-half of the injected fluids even with the use of conventional surfactants that lower the air/water interfacial tension. Large quantities of fluid are trapped in the reservoir surrounding the wellbore, and in the case of hydraulic fracturing, the fluid is trapped in the region surrounding the fracture and within the fracture itself. This trapped fluid has a detrimental effect on the relative permeability, effective flow area, fracture length, and well productivity. More factors than simple air/water surface tension influence cleanup of injected fluids. A factor often over-looked is interfacial tension between rock and injected fluid, which is of prime importance in dictating capillary pressure and capillary end effects in gas wells. Fig. 1 shows a hydraulic fracture with injected fluid surrounding the propped fracture. Gas breaks through at the point of least resistance (e.g., at the fracture tip or near the wellbore), leaving injected fluid trapped. The gas then channels at the top of the fracture, bypassing a large percentage of the injected fluid. Water saturation at the fracture face and within areas of the propped fracture adversely affects the relative permeability to gas, significantly impairing gas flow into and through the propped fracture. In low-pressure environments, swabbing is used to initiate gas flow. Often, even long swabbing times achieve only 50% cleanup. Surfactant-Property Comparison Conventional Surfactants. Surfactants are a group of chemicals consisting of hydrophobic and hydrophilic tails that alter the surface activity of aqueous media. When a surfactant is dissolved in an aqueous medium, its hydrophobic group distorts the hydrogen bonds between the water molecules around the hydrophobic group, resulting in decreased surface tension between the hydrophobic groups and water. Both hydrophobic and hydrophilic groups of surface-active agents play an important role in this phenomenon. The hydrophobic portion normally is made up of hydrocarbons ranging from C8 to C18 and can be aliphatic, aromatic, or a mixture of both. The main sources of hydrophobes are natural fats, oils, petroleum fractions, synthetic alcohols, or polymers. The classification of the surfactant comes from the hydrophilic group of the surfactant. This portion identifies surfactants as being anionic, cationic, zwiterionic, or nonionic. In this work, the nonionic surfactants are used because of their compatibility with fluid systems used in the Appalachian basin. Two classes used are the aliphatic ethoxylates (AEs) and nonyl phenol ethoxylates.

Compatibility of Resin-Coated Proppants With Crosslinked Fracturing Fluids

Summary This paper describes the additive interaction and/or compatibility of various resin-coated proppants (RCP's) with low-, neutral-, and high-pH water-based fracturing fluids. Solutions are provided for those fluids exhibiting compatibility problems with RCP's.

Evaluation of Fracturing Results in Deviated Wellbores Through On-Site Measurements

Summary Four adjacent oil wells in the Kuparuk River oil field, with deviated angles of 6°5′, 24°6′, 27°, and 36°7′ from the vertical at the perforations, were analyzed with prefracturing tests. The total fluid volume for these tests varied from 645 to 840 bbl [103 to 134 m3] of either clean lease oil or water-based fracturing fluid at low to intermediate rates (up to 15 bbl/min [2.4 m3/min]). These wells Were subsequently fractured with proppant-laden fluid. A series of instantaneous shut-in pressures (ISIP's) was obtained for each well. ISIP's and fracturing pressures decreased with time in two of the four wells with a relatively high friction pressure at the end of the pumping. A radially propagating fracture from a point source of pressure explains this decreasing pressure with time. The elasticity theory predicts that a fracture in a deviated, cased wellbore should intersect the wellbore at one location. Only when the deviated wellbore azimuth is near that of the fracture orientation does the fracture sweep the entire perforated zone. This observation of the fracture orientation relative to the wellbore azimuth based on the pressure analysis is enhanced further by postfracture temperature surveys. It appears that only a relatively small volume of proppant could be displaced in a deviated wellbore. The degree of deviation, however, did not appear to be a major concern in the treatment size.

Crosslinked Acid Gel

Abstract A new, stable, crosslinked acid gel has been developed jar fracture acidizing applications. This crosslinked acid can be prepared from acid strengths up to 28 per cent hydrochloric acid. Laboratory tests show the fluid possesses high viscosity and shear stability at temperatures up to 93 °C(200 °F). Viscosity of the acid gel can be reduced in a controlled manner by a chemical additive to aid well cleanup. Rheological data were obtained in a newly designed Viscometer, the pressure rheometer. The rheometer used a bob/cup arrangement to measure the fluid rheology and the fluid was fed to the gap between the bob and cup. A desired pressure was directly applied to the test fluid without using a second pressurizing fluid such as mineral oil or nitrogen. In addition to its viscosity characteristics, the acid reactivity of the crosslinked acid gel with limestone specimens, in a dynamic reaction setup, is drastically retarded. The crosslinked fluid is also residue free in live or spent acid minimizing formation damage. This newly developed fracture acidizing fluid possesses other important fracturing fluid properties such as low friction pressure, good proppant transport characteristics, and good fluid loss control. Results from computer simulation of fracture acidizing treatments indicate deeper penetration is achieved by the cross- linked acid compared to unaltered acid. Field results also show that in several carbonaceous formations, production could be substantially improved if stimulated with this crosslinked acid. Introduction Hydrochloric acid, ranging in strength from 3 to 28% has been used to commercially stimulate carbonate formations since 1932(1). However, the reaction of HC1 (hydrochloric acid) with carbonate rock occurs too rapidly resulting in a limited depth of penetration of live acid into the formation. In order to increase the depth of penetration, acids have been retarded by: adding a suitable gelling agent(2), adding chemical retarders(3), foaming the acid(4), emulsifying the acid(3), or by crosslinking suitable acid gelling agents(5). Each method of retardation has limited use in field application. With the exception of cross-linked acid, each of these methods generate fluids of low viscosity and a low degree of viscous stability (viscosity changing with time) with increasing reservoir temperature. If hydrochloric acid can be crosslinked to generate high viscosity and better viscous stability then not only will it be possible to retard the acid spending but it will also produce longer and wider fractures. Furthermore, crosslinked fluids normally have lower leakoff rate to the formation during pumping than uncrosslinked fluids. This paper presents a newly formulated crosslinked acid gel developed for fracture acidizing. Rheology, acid reaction rate, fluid loss, friction pressure and sand fall data obtained from laboratory studies will be presented. Results obtained from field application of this crosslinked acid will also be presented. The Crosslinked Acid System Crosslinked acid was formulated to be easily mixed on the well site. The system is similar to other commercial crosslinked water-based fracturing fluids commonly used for hydraulic fracturing.

Performance of Fracturing Fluid Loss Agents Under Dynamic Conditions

Abstract Fluid loss agents for crude oil and for water have been studied in dynamic tests. A treatment using a spearhead with a fluid loss agent followed by plain fluid appears feasible in crude oil, but not in water. An equation for spearhead depletion shows that spurt loss relative to fracture width must be low, if the portion of spearhead fluid in the treatment is to be small. The presence of colloidal matter in crude oils aids the fluid loss agent. Unlike in kerosene, where flow limited the agent deposition, in crude oils the filter cake continually formed and leak-oil declined. The volume-time relation varied somewhat for different crudes, but was best described by a square root of time function. Spurt loss was inversely proportional to agent concentration. After the fluid loss agent initiated the filter cake, the crude oil colloids built on it effectively. A 2-minute or a 5-minute spearhead with double the normal agent concentration gave the same fluid loss curve as the same concentration did for a 30-minute test. The agents tested in water gave fluid loss plots on which, for the first few minutes, volume was proportional to the square root of time, but later became proportional to time. For fracture area calculation the customary square root of time function is a satisfactory approximation. Leak-off rates and spurt losses were higher in water systems than in oils. The spurt loss tended to be inversely proportional to concentration. In spearhead tests, the filter cakes were not eroded by water flow. However, the rather high spurt loss values make spearhead treatments impractical for water-based fluids. Introduction The effects of dynamic testing conditions on the performance of fluid loss agents in kerosene have been studied previously. We have extended the work to include crude-oil and water-based fracturing fluids. An understanding has been gained of the mechanisms of formation and functioning of the filter cakes of fluid loss agents. The practical aspects of evaluating performance of agents in relation to fracture area calculations also are considered. The feasibility of using the fluid loss agent in a spearhead stage of the treatment is examined further for both types of fluids. Experimental Procedure The dynamic fluid loss tests were performed in an apparatus similar to the high-pressure apparatus described in a previous publication. A fracturing fluid was circulated over a rock surface located in a closed pressurized loop. The fluid flowed axially over the cylindrical surface of a core 2 in. in diameter X 3.5 in. long, mounted (with the flat ends sealed off) in a pipe, with 0.1 17 in. annular clearance. The filtrate was collected in a central hole in the core and led through valves to graduated cylinders. Provision was made for changing quickly the circulating fluid during the test (spearhead runs) without interrupting the filtration pressure. The only modifications were to add heating tapes and water jackets for the tests with crude oils, all conducted at 150F, and to change all parts exposed to the test fluid to stainless steel for the tests with water-based fluids. The latter tests were made at room temperature, 80F. Three crude oils were tested. A mixed crude, obtained from a local refinery, contained a considerable amount of light ends. For safety reasons, it was stripped to 250F vapor temperature before use in the fluid loss tests. The other two oils were used as obtained from lease tanks. One was a greenish-brown, 37 deg. API paraffinic crude, and the other was a black, 32 deg. API asphaltic crude. The fluid loss agent for oil, here designated for brevity as Agent A, was Adomite Mark II*, a granular solid commercial agent, the same as previously tested in kerosene. Three different compositions of fluid loss agents were tested in Tulsa tap water. Agent B was Adomite Aqua*, a solid commercial fluid loss agent, comprising clays and hydrophilic gums principally derived from starch. Agent C was a mixture of three parts of Agent B with two parts of silica flour. Agent D was Dowell J137, a mixture of guar gum and silica flour. The test cores were cut from contiguous blocks of Berea or Bandera sandstones. For the oil tests, the cores were oven dried, evacuated, saturated with kerosene, and the kerosene permeability was measured. The cores used with the water-based fluids were pretreated by saturating with 3 percent calcium chloride solution to minimize permeability damage by the fresh water due to clay migration. JPT P. 763ˆ