bluuebunny/crossref_metadata_2025 huggingface dataset:
Proppant Transport of Fracturing Gels is Influenced by Proppant Type
Authors: Harris Phillip C. , Heath Stanley J.
Published: January 2009

Fracturing gels are formulated to have a high viscosity sufficient to generate fracture geometry and transport proppant materials. Fracturing fluids are subjected to extensive QA/QC testing on high-temperature rheometers to ensure they have adequate viscosity to perform the intended task and break within a time frame suitable for the operation performed. Although most rheological tests incorporate only the gelled fluid without proppant materials, it is assumed that the fluid will transport proppants to their desired location.

A field location reported that treatments containing certain proppants were screening out more frequently. Tests were performed on a slurry viscometer (SV). It was discovered that not all proppant materials of the same nominal size and density were transported equally when added to a fracturing gel. The typical properties of the borate gels were measured, but no significant differences were found that would account for differences in transport. All the proppants had nominal 20/40 mesh size. A laser analysis of the particles indicated small differences in the distribution of sizes. However, the size analysis did not fit the trend that "bigger settles faster."

Scanning electron micrographs showed differences in surface roughness between the ceramic materials and sand. The proppants were coated with a tacky substance to neutralize any chemical absorption effects. The coated proppants then settled in a manner consistent with their physical characteristics (size and density), but the tacky material caused agglomeration and faster settling than before. The coated proppants were treated chemically to temporarily disable the tackiness, and it was observed that all the materials settled in a manner consistent with their physical characteristics.

It was found that certain 20/40-mesh proppants were suspended twice as long as other proppants in the same gel environment. The proppant effect was measured with the SV. The trend from the SV instrument correlated well with the screenout rate observed in the field.

Analysis indicated a surface catalytic effect of ceramic proppants causing faster decomposition of oxidizing breakers and accelerated gel breaking. This effect was absent in fluids with uncoated sand. Some resin-coated proppants were found to also accelerate breaking because of leaching of chemical compounds from the coatings.

Therefore, it is not correct to assume that all proppants added to fracturing gels will be transported equally. Viscosity measurements of gels without proppant might not give accurate information about the behavior of gels with proppant if the proppant interacts with the gels.
Optic Fiber Distributed Temperature for Fracture Stimulation Diagnostics and Well Performance Evaluation
Authors: Huckabee Paul
Published: January 2009

This paper summarizes applications of optic fiber (OF) distributed temperature sensing (DTS) technology for hydraulic fracturing stimulation diagnostics and well performance evaluation in unconventional gas well completions. Results are presented for temporary "call-out" deployments, velocity string installations, and permanent "behind casing" installations in vertical and horizontal wellbores. It is demonstrated that OF-DTS enables quantitative inflow distribution measurement for well performance evaluations in commingled multiple interval completions. OF-DTS is also shown to demonstrate the near wellbore dynamic placement characteristics during hydraulic fracture stimulation operations and, in one example, enables a superior volume distribution evaluation than radioactive (RA) tracer surveys. OF-DTS is demonstrated to be complimentary to RA tracer surveys in some cases. Additionally, this technology is being applied successfully for validation of hydraulic fracture containment in disposal well injection applications.
Propped Fracturing in High Temperature Deep Carbonate Formation
Authors: Li Yongping , Wang Yonghui , Cheng Xingsheng , Che Mingguang , Zhang Fuxiang , Peng Jianxin
Published: January 2009

Acid fracturing, as a conventional and effective stimulation method, has been widely used in carbonate formation. But because of serious acid leak-off and rapid acid/rock reaction speed, the length of effective acid etched fracture is always restricted, even the high viscosity acid and emulsified acid were applied; besides the effective duration of etched fracture was short, especially in deep well, because of the high closure stress acted on the fracture wall where the rock were softened significantly after contact with acid. In contrast, propped fracturing can create longer conductive fracture, and its effective duration is longer because the existence of proppant.

The carbonate reservoir are deeply buried (>4500m) with high temperature (>130°C), ultra-low porosity/permeability, high young's modulus and tensile strength, and the natural fractures often densely distributed in it, all of which makes the propped fracturing difficult. A new temperature-stability and shearing resistance delayed cross-linked guar fracturing fluid with low damage was developed to qualify for the fracturing treatment. Small size high strength ceramic proppant was selected to fulfill the narrow width of fracture, and proppant slugs was utilized to erode the tortuousness of near-wellbore fracture path and plug near-wellbore multiple hydraulic and natural fractures. The technology countermeasure ensured the success of propped fracturing treatment.

The net pressure and production history matching both indicated that the propped fracturing created longer conductive fracture and realized deep penetration. The well production increased dramatically after the stimulation. Besides, the comparison of production after gelled acid fracturing, surface cross-linked acid fracturing and propped fracturing in the same layer same well suggested that propped fracturing was more effective than the acid fracturing. The production test further showed propped fracturing could provide longer effective duration, and the well rate-maintenance capability was very excellent.
First Application of High Density Fracturing Fluid to Stimulate a High Pressure and High Temperature Tight Gas Producer Sandstone Formation of Saudi Arabia
Authors: Bartko K. , Arocha C. , Mukherjee T. S. , Sierra L. , Terracina J. , Lord P.
Published: January 2009

Recently Saudi Aramco and international companies started an aggressive gas exploration campaign in tight gas sandstone formations. In most of the cases the prospective tight gas producing zones were discovered at a depth below 20,000 feet where the stress and temperature are extremely high and the reservoir permeability conditions are low; being necessary in all cases to fracture stimulate each horizon to define the fluid and evaluate productivity.

The extreme stress and temperature conditions are actually one of the main challenges to perform fracture stimulations on this type of formation, this because the fracturing fluid needs to be stable, induce minimum damage and have good proppant transport capabilities at high temperature conditions.

As a part of the referenced exploration activity in the first quarter of 2008 Saudi Aramco has the challenge to perform a proppant fracture stimulation in a deep tight gas on shore sandstone formation where the temperature and stress conditions (375° F and 1.1 psi/ft at 20,000 feet) exceeded the working pressure capability of the available equipment and the existing fracturing fluids application limits. To answer the referenced challenges and knowing that 20,000 psi fracturing equipment is not available in the area an extensive laboratory evaluation was done to design a new high density fracturing fluid. After a lengthy laboratory evaluation, we were able to select a regional supplier for the 1.48 specific gravity (12.3 lb/gal) heavy brine used as the base fluid and prepare a user friendly cross linked fluid for the referenced field application. The new fluid system was successfully mixed and pumped in the field enabled the treatment of the well through lower surface treating pressure with conventional 15,000 psi equipment, lower horsepower requirements, and a safer work environment.

The paper summarizes the well conditions, extensive fluid qualification testing, procedures, and specially learned lessons during the referenced first field application of the new fracturing fluid system.
A Multi-Continuum Model for Gas Production in Tight Fractured Reservoirs
Authors: Wu Yu-Shu , Moridis George , Bai Baojun , Zhang Keni
Published: January 2009

Tight gas reservoirs are characterized by single-phase (gas) or two-phase (gas and liquid) flow in extremely low-permeability, highly heterogeneous porous/fractured, and stress-sensitive rock. Gas flow in such tight formations is further complicated by other co-existing processes, such as Klinkenberg effect, non-Newtonian or non-Darcy flow behavior, due to strong interaction between fluid molecules and solid materials within tiny pores, or micro- and macro- fractures. Because of the low permeability in tight rock, the traditional double-porosity model may not be applicable for handling fracture-matrix interaction of gas flow in these reservoirs. In this work, we present a generalized mathematical model for simulating multiphase flow of gas in tight, porous/fractured reservoirs using a more general, multi-continuum modeling approach. The model incorporates the following processes: (1) Klinkenberg effect, (2) non-Newtonian behavior (i.e., threshold pressure gradient for flow to occur); (3) non-Darcy flow with inertial effects; and (4) rock deformation due to changes in the stress field. We propose to explicitly separate effects of rock mechanical deformation and molecular interaction between fluids and rock materials. The former effect is included using the intrinsic permeability and porosity relations, while the latter is accounted for by an apparent viscosity for non-Newtonian, non-Darcy's behavior, or a modified permeability for Klinkenberg effect

The proposed mathematical model has been implemented into a multiphase, multidimensional reservoir simulator. In the numerical model, specifically, a control-volume, integral finite-difference method is used for spatial discretization with an unstructured grid, and a first-order finite-difference scheme is adapted for temporal discretization of governing two-phase flow equations in tight gas reservoirs. The resulting discrete nonlinear equations are solved fully implicitly by Newton iteration. The numerical scheme has been verified against analytical solutions with Klinkenburg effect, non-Newtonian or non-Darcy flow, and flow in deformable fractured rock in our previous studies. The model's application to actual tight gas reservoirs is an on-going research project.
Investigation of Flow Behavior of Slick-Water in Large Straight and Coiled Tubing
Authors: Shah S. N. , Kamel A. H. Ahmed
Published: January 2009

Low damage fracturing fluids are normally utilized for better fracture dimensions confinement and lower residue. This leads to not only longer fracture lengths, but also, higher fracture conductivity. Slick-water fracturing technology - developed in the 1980s - is less expensive than gel treatments. Fluid and proppant volumes can be reduced and treatment flow rates can be significantly increased. When compared to conventional gel treatments, slick-water fracturing can generate similar or better production responses.

In frac treatments, slick-water is pumped through straight as well as coiled tubing. As a result of secondary flow, friction pressure losses in CT are higher than in straight tubing. Determining these losses is of utmost importance for successful treatments. Customarily, laboratory generated flow data are used to develop correlations to predict friction pressure of fluids flowing in ST and CT. These correlations are then, without verification, applied to field application which employ much larger conduit sizes.

The present study is aimed to experimentally investigate the hydraulic properties of the commonly used drag reducer; Nalco ASP-820 in larger tubing sizes. It is a modified partially-hydrolyzed polyacrylamide, PHPA. Previously, we reported flow data gathered employing a ½-in. ST and CT (varying curvature ratio) and the correlations developed to predict friction losses of fluids in ST and CT. In this investigation, the large-scale flow data acquired from 200-ft ST and 1,000, 2,000, and 3,000-ft, 1½-in. CT, and 1,000-ft 2⅜- and 2⅞-in. CT are compared with the predictions from the correlations developed from ½-in. pipe data. The effects of shear intensity, shear duration, and pipe roughness on flow properties of ASP fluid are also investigated.

Results show significantly lower drag reduction in CT than in ST due to secondary flow caused by the tubing curvature. Polymer degradation because of shear (shear intensity and duration) and/or tubing roughness can significantly reduce drag reduction. The results are discussed in light of a recently developed "Drag Reduction Envelope" to evaluate the drag reduction characteristics of slick-water fluid in ST and CT.
Examining Our Assumptions – Have Oversimplifications Jeopardized Our Ability to Design Optimal Fracture Treatments?
Authors: Vincent M. C.
Published: January 2009

In the design of hydraulic fractures, it is necessary to make simplifying assumptions. Fifty years ago, our industry was mathematically obliged to describe fractures as simple, planar structures when attempting to predict fracture geometry and optimize treatments. Although computing tools have improved, as an industry we remain incapable of fully describing the complexity of the fracture, reservoir, and fluid flow regimes. Generally, we make some or all of the following assumptions: –Simple, planar, bi-wing fractures–Completely vertical fractures with perfect connection to the wellbore–Flow capacity that is reasonably described by published conductivity data–Predictable fracture width providing dependable hydraulic continuity (lateral and vertical continuity)

To forecast production from these fractures, we frequently make the additional assumptions: –Reservoir is laterally homogeneous–Modest/no barriers to vertical flow in formation (simplified description of layering compared to reality)

However, we must recognize that all of these assumptions are imperfect. This paper will investigate the evidence suggesting that fractures are often subject to: –Complicated flow regimes–Complicated geometry–Irregular frac faces–Imperfect proppant distribution–Imperfect hydraulic continuity–Imperfect wellbore-to-fracture connection–Residual gel damage, possibly including complete plugging or fracture occlusion

Additionally, reservoirs are known to contain flow barriers that amplify the need for fractures to provide hydraulic continuity in both vertical and lateral extent.

The paper appendix tabulates the results from more than 200 published field studies in which fracture design was altered to improve production. Frequently the field results cannot be explained with our simplistic assumptions. This paper will list the design changes successfully implemented to accommodate real-world complexities that are not described in simplistic models or conventional rules of thumb. Field examples from a variety of reservoir and completion types [tight gas, modest perm oil, coalbed methane, low rate shallow gas, annular gravel packs] will be provided to demonstrate where the field results differ from expectations, and what adjustments are necessary to history-match the results.
Inflow Performance for a Hydraulic Fracture in a Deviated Well
Authors: Zhang Y. , Ehlig-Economides C. A. , Han G. , Tosic S. , Economides M. J.
Published: January 2009

Wells in high permeability reservoirs are frequently constructed with deviated wellbores completed with a high permeability fracture (HPF). If the deviated well is not drilled perpendicular to the minimum horizontal stress, significant misalignment between the wellbore and the fracture plane is likely to occur. In turn this leads to limited communication between the fracture and the wellbore, resulting in a reduced number of flowing perforations and additional pressure drop. In low permeability reservoirs, even for a misaligned fracture the majority of the flow is through the hydraulic fracture. In contrast in deviated HPF wells a significant flow contribution may be through the gravel pack (GP) perforations that are not connected to the fracture, thus bypassing the fracture. The flow fraction bypassing the fracture depends on the formation permeability and the fracture and gravel pack skins. This paper will show that the conventional inflow performance calculations can not be applied for a HPF well with a misaligned fracture. It is generally incorrect to treat the inflow performance for a deviated HPF well in the same manner as for a vertical well.

This paper provides a semi-analytical model for the flow pattern taking into account both flow to the fracture and flow that bypasses the fracture to the GP wellbore region. The model shows that the limited communication between hydraulic fracture and wellbore has a great impact on the entire flow pattern. A field example with a deviated deepwater well (DW) from the Gulf of Mexico (GOM) will be shown. The flux method will be revised taking into account flow contribution from the GP region, resulting in additional flow perforations but adding more risk for fines movement and skin increase.
Stress Amplification and Arch Dimensions In Proppant Beds Deposited by Waterfracs
Authors: Warpinski N. R.
Published: January 2009

Equations and a procedure have been developed to calculate the excess stress induced on a proppant dune that is deposited by a waterfrac with poor proppant transport characteristics. This method also calculates the dimensions of an arch region that forms above the bed. Stresses on the proppant at the top of such a dune are much greater than usually considered because of the need to support a wide proppant bed and the arch, suggesting that crushing and embedment are likely. The arch region itself is an extremely high conductivity pathway that may provide overall benefit in terms of clean-up and production, but may also aid sand production.
2D Modeling of Hydraulic Fracture Initiating at a Wellbore with or without Microannulus
Authors: Cherny S. G. , Lapin V. N. , Chirkov D. V. , Alekseenko O. P. , Medvedev O. O.
Published: January 2009

The goal of this paper is to investigate the near-wellbore phenomena with respect to fracture initiation. The 2D numerical model was developed, which takes into account the interaction of steel casing, cement, and surrounding rock and allows for a curved path of the fracture. The model incorporates an effective finite-difference numerical method for solving a system of coupled differential equations: 1D equations of power law fluid flow along the fracture trajectory and 2D equations of the linear elasticity for rock massif. The model predicts and evaluates the near-wellbore fracture pinching effect as a function of fracture trajectory, perforation misalignment angle, cement/formation properties, stress contrast, and fracturing fluid parameters.

The model developed has a limitation: it does not take into account the leakoff and pore pressure changes in near-wellbore zone during fracturing treatment. However, we believe that this limitation is not essential as it does not affect the quality of results obtained and can be eliminated easily.

Several different scenarios of fracture initiation and propagation were considered. We modeled the initiation and propagation of the fracture through the narrow channel (microannulus) along cement-rock interface as well as along the misaligned perforation. We also investigated different geometries of microannulus development and made conclusions on the most probable situation for different formation conditions. We conducted the comparative analysis of pressure drops and fracture width reductions for different types of fracture propagation. We also modeled fracture propagation for different perforation phasing angles. Based on the results of numerical experiments, we are able to provide some recommendations on how to avoid the worst case of the fracture initiation scenario.
The Effect of Proppant Distribution and Un-Propped Fracture Conductivity on Well Performance in Unconventional Gas Reservoirs
Authors: Cipolla C. L. , Lolon E. P. , Mayerhofer M. J. , Warpinski N. R.
Published: January 2009

Microseismic fracture mapping has provided significant insights into the nature of fracture growth in unconventional gas reservoirs (primarily shale) and allowed detailed characterization of the created network size and to a lesser extent the internal network structure (i.e., fracture spacings, azimuths, and degree of complexity). Fracture mapping has shown that large volume slickwater stimulations can access millions of square feet of reservoir area. In most unconventional gas reservoirs, well performance is directly related to the size and complexity of the fracture network; however, well performance is also affected by un-propped and propped fracture conductivity and proppant distribution within the fracture network. This paper examines the relationship between network size, proppant distribution, and well performance.

A series of reservoir simulations were used to quantify the effect of network fracture conductivity and proppant distribution on well performance. The simulations evaluate a range of reservoir permeability from 0.0001 to 0.01 mD and utilize a network size and fracture spacing that is consistent with microseismic mapping measurements. Proppant transport cannot be reliably modeled in complex fracture networks, but it is likely that much of the fracture network is un-propped (Cipolla et al.2008). Un-propped fracture conductivities of 0.5 to 5 mD-ft were evaluated in this study. This work investigates the effect of proppant transport from a primary fracture into a fracture network and proppant banking in the primary fracture on well productivity. The results of the reservoir simulations illustrate the likely impact of stimulation designs on well performance. The results from this work provide a better understanding of fracture conductivity requirements in unconventional gas reservoirs that can be used to improve stimulation designs through improved proppant selection and scheduling.

The results of the reservoir modeling show that proppant transport, even short distances, into the fracture network can have a significant affect on well productivity in cases where un-propped fracture conductivity is not adequate to fully exploit fracture complexity. In addition, proppant banking is likely with the low viscosity fluids used in many fracture treatments in unconventional gas reservoirs, which will result in the formation of a high conductivity arch at the top of the proppant bank. The impact of this high conductivity arch can be significant and affect treatment designs, many times reducing proppant volumes and conductivity requirements.
Computing Estimated Values of Optimal Fracture Half Length in the Tight Gas Sand Advisor Program
Authors: Wei Y. N. , Holditch S. A.
Published: January 2009

Producing natural gas from Tight Gas Sand (TGS) reservoirs is currently very important to the industry in North America and will be of increasing importance to the global energy industry in the coming decades. We are developing a TGS Advisory system to provide advice to engineers evaluating and developing tight gas sand reservoirs. The program can be used to establish best practices for drilling, completing, stimulating and producing a TGS reservoir as a function of the reservoir properties. We have combined knowledge from the petroleum literature and interviews with experts with detailed calculations to build TGS Advisor.

One of the most important problems for TGS reservoirs is to determine the optimum fracture half-length as a function of the reservoir properties. In this paper, we will describe three methods to calculate the optimum fracture half length, which include using 2-D fracture design equations, the unified fracture design method, and a rule-of-thumb method using the values of formation permeability and expected drainage area. With these three estimated values of optimum fracture half-length, the user can confidently use a 3-D or Pseudo 3-D fracture design model to generate the more detailed fracture treatment design. All the three methods have been incorporated into the TGS Advisory system. An example of using TGS Advisor to estimate the optimal fracture half-length will be presented.
Fracture Growth in Horizontal Injectors
Authors: Suri A. , Sharma M. M.
Published: January 2009

Horizontal wells are increasingly used worldwide and are especially desirable offshore for water-flooding and reservoir pressure maintenance as they allow more access to the reservoir with large injectivities. Fracture growth in these horizontal injectors can play an important role in determining the injection rates, reservoir sweep and oil recovery.

A model is developed to estimate the growth of fractures in horizontal injectors. The model considers two orientations of fracture growth: 1) longitudinal fractures i.e. fracture along the horizontal well and 2) centered transverse fractures, i.e. at the center and perpendicular to the horizontal well. Fracture growth is due to: 1) reduction of permeability around the horizontal well caused by particle deposition from injection fluids, 2) reduction in minimum horizontal stress due to cold fluid injection, and 3) injection of viscous polymer fluids. The model accounts for plugging of the horizontal well, the induced fracture and the formation around the fracture. It also calculates the thermal and pore pressure stresses to update the minimum horizontal stress around the fracture tip. It also allows injection of power-law fluids to model polymer injection in horizontal injectors.

It is shown that the injection well pressures are controlled by the minimum horizontal stress. The injection fluid quality, injection rate, and injection fluid temperature determine the rate of fracture growth in a horizontal injector. Fracture lengths are estimated for longitudinal and transverse fracture growth orientations as the lower and upper bound values.
New Frac Fluid Provides Excellent Proppant Transport and High Conductivity
Authors: Walters Harold G. , Stegent Neil , Harris Phillip C.
Published: January 2009

A new clean biopolymer-based fracturing fluid has been developed. The new fluid has high conductivity, stable viscosity, low pipe friction, excellent proppant transport, and the capability to be used with produced water. This fluid-system development effort was aided by the evolution of a new approach to proppant transport measurement as well as the operational deployment of a dry-polymer blender used to effectively hydrate the fluid system as part of an on-the-fly treatment. The new fluid has been field-trialed in 14 frac stages over four wells with about two million pounds of proppant placed. The application of the new fluid and experience of the field-trials are discussed.

This new clean fluid is widely applicable to fracturing low-permeability reservoirs worldwide and can be used where both waterfrac and traditional gelled fluids are currently used. This fluid signals a dramatic shift in fracturing low-permeability unconventional reservoirs by coupling excellent proppant transport with high conductivity.
Maximizing Return on Fracturing Investment by Using Ultra-Lightweight Proppants to Optimize Effective Fracture Area: Can Less Really Deliver More?
Authors: Brannon Harold D. , Starks Thomas R.
Published: January 2009

Hydraulic fracture deliverability is largely defined by the fracture area exhibiting sufficient conductivity contrast within the productive reservoir interval. Increasing effective fracture area has typically been addressed by employing larger treatments and proppant volumes, resulting in increased stimulation treatment costs, which unless accompanied by similar increase in the value of the incremental well productivity, has negative implications on ROFI.

The introduction of ultra-lightweight proppants having superior proppant transportability relative to conventional proppants and sufficient strength to withstand the harsh environments has spurred renewed interest in the application of proppant partial monolayers (PMLs). A properly placed partial monolayer exhibits conductivity equivalent to packed fractures having greater than ten proppant layers. The enhanced transportability of the ULW proppants allows for distribution over a much greater portion of the created fracture area. Thus, ULW proppant partial monolayers equate to a high conductivity fracture with much reduced volumes of proppant distributed across a larger area than can be achieved with conventional proppants. Case histories of PML fracturing treatments have consistently illustrated stimulated production increases well beyond expectations, effectively validating the productivity benefits of the process. This paper compares effective fracture area, fracture conductivity, and resultant production simulations for ULW proppants partial monolayer fracturing treatment designs with those of conventional proppant packed fractures. Normalized stimulation costs of the respective treatment designs are subsequently compared with the stimulated fracture deliverability to assess the respective Return-On-Fracture-Investment.
Solid Production Chemicals Added with the Frac for Scale, Paraffin and Asphaltene Inhibition
Authors: Gupta D. V. S. , Szymczak Steve , Brown Mike J.
Published: January 2009

Prolonged chemical inhibition is the desired outcome from placing a solid inhibitor in a formation during the fracturing process. Traditionally liquid inhibitors applied through a squeeze have provided inhibition for up to one year and sometimes longer. Deepwater operators, especially, desire longer inhibition periods. This paper reports on new fracture compatible chemistry that has been applied on over five hundred wells for the inhibition of mineral scale. It also reports on similar products for the inhibition of paraffin and asphaltene. These applications have been in deepwater, tight gas and coal bed methane formations. The longest documented treatment has been in the ground for over three and a half years. The highest cumulative water production with acceptable scale inhibitor residuals has been over 1,000,000 bbls of water.

Placing a solid chemical inhibitor into the formation via the fracturing process requires a product that is compatible with the fracturing fluid, does not adversely affect conductivity and provides long term inhibition through the controlled release of the inhibitor into the produced fluid. The solid inhibitor is added to the fracturing proppant. Primarily this is a mass-balance process by which a finite amount of inhibitor desorbs over time. The goal is to maximize the inhibitor loading and minimize the chemical release rate without negatively impacting the stimulation.

In the treated wells, inorganic and organic deposition has been arrested for extended periods when compared to alternative liquid addition applications. This is a direct result of the placement of the inhibitor in the formation during the fracturing process. All wells have shown inhibition, as measured by produced fluid sample analyses.

All operators with deposition potential must undertake significant remedial intervention measures. This new chemical technology extends the life of a chemical inhibitor placement beyond traditional expectations. The advancement of this technology has reduced deposition-related failures and reduced well intervention costs.
Unconventional Fracturing Fluids for Tight Gas Reservoirs
Authors: Gupta D. V. S.
Published: January 2009

Many tight gas formations are water-wet and under-saturated where the initial water saturation in the reservoir is less than the capillary equilibrium irreducible water saturation. The use of water-based conventional fracturing fluids causes water to be trapped in the near-wellbore region, thereby significantly impairing the ability of gas to flow. Formations with sub-irreducible water saturation can be stimulated with fluids that minimize the interfacial tension (such as surfactant gels), minimize the amount of water used in the fluid (such as energized or foamed fluids), dehydrate the formation (such as alcohol-based fluids) or completely eliminate water (such as hydrocarbon-based or liquid carbon dioxide-based fluids). Since the rheology and proppant-carrying properties of these fluids vary, the uses of these fluids are different and will be discussed in detail in the paper. The paper will also present guidelines, based on formation properties, to indicate the need for considering unconventional fluids.
Hydraulic Fracturing: Modeling and Optimization Using Latest Generation Logs and Conductivity Optimization Technologies
Authors: Espina C. , Baldassa D. , Sorenson F. , López E. , Bonapace J. , Quintavalla C.
Published: January 2009

Successful hydrocarbon production in the San Jorge Basin in Argentina is achieved with understanding the high variations in reservoir fluid properties, discriminating the complex lithology, and achieving the optimum hydraulic fractures. This paper outlines how state of the art logging tools and collaboration between the operating and service companies can deliver improved fracture results.

The multi-layered stratigraphic formations in the San Jorge Basin have long presented formation evaluation challenges with conventional well logging. These formations exhibit major inconsistencies and anomalous results in formation water salinity. In addition, the complex reservoir characteristics have required the use of hydraulic fracturing to improve the hydrocarbon production during the past fifteen years.

Nowadays, petrophysical evaluation of the reservoirs has been improved using the latest well logging technology such as Nuclear Magnetic Resonance (NMR) logs to identify and distinguish potential productive layers and zones to be stimulated.

Combining NMR logging technology with fracture height evaluation utilizing azimuthal shear wave slowness data, stimulation treatment pressure responses, and post-stimulation swab test results, provides sufficient data to calibrate geomechanical and hydraulic fracturing models. With advanced interpretation techniques and modeling, the optimum fracture can be designed and performance data from that fracture can be used to validate the theoretical models. This approach enhances the capability to design hydraulic fractures based on the reservoir conditions, with the optimum conductivity and fracture half-length to provide the required productivity over the life of the well.

Application of this process has resulted in improved well performance in the San Jorge Basin wells. The integration and interpretation of information between the operator and the service companies resulted in more accurate and optimized work flows and modeling for the complex and non-conventional reservoirs of the San Jorge Basin. As companies work together in a collaborative environment to address business challenges, solutions have been generated that no single company could have achieved alone.
Increasing Reservoir Contact by Combining Mechanical Diversion and Unique Stimulation Chemistry
Authors: Veillette Christian P. , Cuzella Jerome J. , Mueller Fred A. , Loayza Michael P. , Malaver Rafael , Abaza Bayan , Gurmen M. Nihat
Published: January 2009

The Edwards Limestone in South Texas often requires stimulation to be commercially productive. The relatively low permeability, high Young's Modulus, presence of natural fractures, minimal stress barriers to control height growth, and formation temperatures up to 375°F provide a challenging environment for a successful stimulation. Conventional stimulation approaches using acid fracturing and proppant fracturing techniques often have resulted in less than optimal effective etched or propped fracture half lengths, respectively.

Horizontal openhole completions have increased the potential reservoir contact to the wellbore, but are not effective without stimulation. Achieving the diversion along the horizontal wellbore that is required to effectively treat the entire interval proved difficult using conventional diversion techniques with particulate and chemical diversion. Furthermore, the difficulty in achieving sufficient fracture width limits the proppant concentration that can be pumped into the formation. Acid fracturing was a desirable stimulation technique, but because of the high reservoir temperature and associated high acid spending rate, it was difficult to achieve a long effective etched half length with acid fracturing.

A unique approach was developed by combining a novel diversion technique with a new stimulation treatment. The diversion technique enables mechanical isolation of the openhole completion during the stimulation treatments. The mechanical diversion system also facilitates efficient pumping of multiple stimulation treatments, resulting in increased reservoir contact to the wellbore. The new stimulation treatment uses a unique lightweight (1.25 SG) proppant-like material that is pumped into the well as an inert substance. The product hydrolyzes only after the solid particles are in the reservoir for an amount of time at temperature. This enables the fracture etching process to occur during shut-in and flowback of the well thus solving the problem of creating long effective etched fracture half lengths with acid. The combination of these two techniques has enabled a much larger stimulated reservoir contact to the wellbore in the Edwards Limestone in South Texas, which leads to improved production.
Quantifying Transient Effects in Altered-Stress Refracturing of Vertical Wells
Authors: Roussel Nicolas Patrick , Sharma Mukul Mani
Published: January 2009

The production or injection of fluids in reservoirs results in a redistribution of stresses. In this paper, the extent of stress reorientation has been calculated for fractured production and injection wells and the results have been analyzed for their impact on refracturing operations. Rules of thumb and charts have been provided to help candidate well selection for refracturing based on the study.

For previously fractured wells, it is possible to create a secondary fracture that is perpendicular to the first fracture. The secondary orthogonal fracture can be created only within a certain time-window that in turn depends on the reservoir properties. Conditions leading to orthogonal secondary fractures in different kinds of reservoirs (oil, gas and tight gas reservoirs) have been analyzed to establish some rules of thumb. The effects of the layers bounding the pay zone and of permeability heterogeneity and anisotropy on stress reorientation are also discussed.

Our results, for the first time, allow us to quantify the phenomenon of orthogonal secondary fracturing around fractured production wells by calculating the extent of the stress reversal region as a function of time. The results of our model are shown to agree qualitatively with field observations obtained from micro-seismic measurements. The model presented in the study helps to demystify the concept of refracturing and provides a quantitative estimate of the time-window for refracturing as a function of dimensionless parameters. The final result demonstrates the potential of the model to increase the reservoir sweep in unconventional reservoirs for which the optimum time-window for refracturing is of the order of months to years. The conclusions of this study are useful for the design of refracturing operations and candidate well selection.
Impact of Capillary Suction on Fracture Face Skin Evolution in Waterblocked Wells
Authors: Mahadevan Jagan , Le Duc , Hoang Hai
Published: January 2009

Hydraulic fracturing operations, carried out by injecting large volumes of water, cause invasion of the injected water into the formation and trapping due to capillarity. This invasion, also termed as water blocking, can cause a reduction in the gas well productivity by reducing the relative permeability of gas with respect to water. The flow of gas toward the wellbore/fracture during production well will result in the removal of water block through viscous displacement as well as evaporation, which occurs primarily due to gas expansion over long period of time. However, recent observations from field show that the productivity of hydraulically fractured wells improves after a period of shut-in leading to a speculation as to whether capillary suction is responsible for the clean-up of water block which eventually leads to productivity improvement. In this work, we solve for the gas relative permeability improvement of the invaded zone of a fractured well accounting for both evaporation and capillary suction. The conservation equations, for both water and gas, are solved numerically to obtain water saturations and gas relative permeability in the damaged zone. Simulations, of gas relative permeability with time, show that when water invasion depth is small, capillary imbibition is the dominant clean up mechanism. For larger depth of invasion, both capillary imbibition and evaporation contribute to the clean-up of water-block leading to the improvement of gas relative permeability in the invaded region. However, when the viscosity of invaded liquid is high, and the liquid mobility is reduced, capillary imbibition maybe negligible and evaporation becomes the dominant clean up mechanism. Our results show that the inclusion of capillary driven flows is important in the prediction of gas well deliverability calculations when water blocking occurs. This study presents a model, combining both viscous removal and evaporation, to calculate the evolution of fracture face skin due to progressive removal of waterblocks and hence well productivity under field conditions.
Overcoming Excessive Fluid Loss in Tip-Screen-Out Stimulations of Depleted, High-Permeability Reservoirs Using a New-Generation Viscoelastic Fluid: Successful Case Histories in West Venezuela
Authors: Parra P. , Miquilena E. , Sánchez A. , Peña A. , Garcia A. , Millán M.
Published: January 2009

Tip-Screen-Out (TSO) stimulations of high permeability reservoirs have been performed in North and South America (i.e., USA, Venezuela, Trinidad, Colombia), in Africa (i.e., Nigeria, Gabon, Congo, Ivory Coast, Cameroon), in Europe (i.e., North Sea, Italy), in the Middle East (i.e., Saudi Arabia) and in Asia (i.e., Indonesia). As reservoirs in these regions mature, fluid loss control and fluid-inflicted formation damage become increasingly important and conflicting issues. On one hand, the use of classic fluid loss additives and/or fluids with good fluid loss control characteristics (i.e., polymer-based fluids) is typically associated with well production impairment because of residues left in the formation. On the other hand, fluids that are considered nondamaging, such as viscoelastic surfactant (VES) fluid systems, typically exhibit limited fluid loss control capabilities, making fluid efficiencies low and proppant placement inadequate. Nondamaging fluids are needed that can deliver adequate fluid loss control under severe reservoir conditions (i.e., upon concomitant occurrence of high permeabilities and low reservoir pressures).

Bachaquero field located in Lake Maracaibo, Venezuela, and managed by Petróleos de Venezuela (PDVSA) is a critical example of these depleted, high-permeability reservoirs. Permeabilities in this field range from 100 mD to 1 D. The average pressure gradient is 0.2 psi/ft. VES fluids typically have been used to hydraulically fracture reservoirs in this field. However, fluid efficiencies observed in recent jobs were as low as 2% and proper proppant placement under these conditions was no longer possible.

In our study, we consider relevant technical aspects and case histories in a systematic study that is aimed at assessing the usefulness of a new-generation VES fluid tailored for high-permeability reservoirs to address low fluid efficiencies in the Bachaquero field. The study encompassed adjustments in fluid formulation to ensure compatibility with local production water and crude oils, specific engineering and quality assurance/quality control guidelines, and field trials in 10 wells, followed by quantification of the enhancements achieved in fluid efficiency and well production.

Field tests showed that fluid efficiencies increased by up to 325%, as compared to conventional VES fluids previously used in this field. Production expectations were exceeded in all tested wells by an average of 65%. The study concluded that the new-generation VES fluid is suitable for use in the Lake Maracaibo area and it has been adopted as the fluid of choice for Bachaquero field. What we learned from this successful campaign is valuable when assessing stimulation strategies for mature high-permeability reservoirs worldwide.
Seismic Velocity Model Calibration Using Dual Monitoring Well Data
Authors: Maxwell S. C. , Zimmer U. , Wolfe J.
Published: January 2009

A hydraulic fracture stimulation was monitored with borehole geophone arrays deployed in two observation wells. The resulting microseismic images showed that the first horizontal well stimulation was characterized by a diffuse cloud of microseismic events, and the production log indicated roughly uniform production along the length of the well. The second horizontal well stimulation was characterized by clustered microseisms, and the production log indicated significant production from the intersection of pre-existing fractures with the well. The resulting case study allowed a comparison of accuracies between a single observation well and two observation wells. A comparison was also made of the microseismic event location accuracy resulting from of the different configurations of observation wells. The dual well observations provide an opportunity for enhanced velocity model validation in addition to enhanced source imaging techniques to provide additional information about the fracture geometry.