Since the introduction of hydraulic fracturing, the industry has been attempting to establish laboratory testing parameters that assist operators and service companies in their effort to select the optimum proppant for a particular field application. An example of this effort is the development of the "long-term baseline conductivity laboratory test" for proppants. While this test is a huge leap forward in subjecting proppant to simulated downhole conditions, it still does not adequately address many additional factors that can impact the effectiveness of the proppant such as: Proppant fines generation and migration in the fracture Proppant resistance to cyclic stress changes Proppant embedment in the fracture face Proppant flowback and pack rearrangement in the fracture Downhole proppant scaling Most proppant choices are currently based on which one has the highest baseline conductivity, cost, and availability. While this approach seems logical, it runs the risk of overlooking or under-valuing other critical factors effecting proppant performance in downhole environments. To better define what constitutes the most effective proppant for a particular application, field cases will be presented that focus on the impact of proppant selection in a number of wells completed in various shale formations. The analysis will examine the production history associated with a variety of proppant choices. In an effort to better understand the production results, a series of lab tests will be performed on the proppants utilized in the field cases. These tests will attempt to establish how these factors (such as proppant fines, cyclic stress, embedment, proppant flowback, and scaling) could be used to explain and support the results of the field cases.

Society of Petroleum Engineers Abstract A new liquid surface-modification system has been developed for coating proppant, dramatically increasing its surface friction and allowing it to interact instantaneously with surrounding particulates. High surface friction between the coated proppant grains allows them to withstand high flow rate, minimizing their flowback potential after fracture-stimulation treatments. According to field results, when this surface-modification material was used as a flowback-control agent after conventional fracturing treatments, it permitted more aggressive flowback procedures. This treatment did not impair conductivity, and in fact, increased proppant conductivity at closure stresses below 4,000 psi. Better vertical proppant distribution occurred in experiments that demonstrated increased hindered settling of proppant resulting from this surface modification. Fines that already existed within the proppant, fines generated from the formation, or fines derived from crushed proppant upon fracture closure all adhered to the treated proppant, which inhibited them from migrating and blocking the pore throats of the proppant pack. This unique coating technology further enhanced conductivity by improving frac-gel breaker action in certain fluids. This behavior results in faster, more effective well cleanup after stimulation. P. 101

Summary Laboratory investigation of the interactions between fracturing fluids andresin-coated proppants (RCP's) revealed (among other conclusions) that RCP'sare incompatible with oxidizing breakers. Areas covered included RCP effect onfluid rheology, fluid relationship to RCP strength, theoretical study ofrequired RCP strengths to prevent flowback, and experimental measurement toestablish minimum strength. Introduction This paper describes the use of curable RCP's in fracturing treatments. Their primary purpose is to prevent proppant flow from the fracture duringcleanup and production. The use of such materials is increasing rapidly, yetmany concerns exist in design and application of fluid systems. These include(1) the effect of various crosslinked fluid systems on the strength of thecured, consolidated sandpack, (2) breaking of the gel system, (3) temperatureeffects on the resin system during curing, (4) the closure stress required tocause consolidation, and (5) the compressive strength required to preventproppant flow from the fracture. Laboratory experiments have been conducted todetermine the effect of various components in crosslinked fluid systems on theconsolidation of curable RCP'S. Available RCP products and field- applied resinsystems were investigated under several different curing conditions. Extendedcuring before stress was applied resulted severely reduced strengths. Flowexperiments (through consolidated packs) with oil and water were conducted tocorrelate velocity/viscosity packs) with oil and water were conducted tocorrelate velocity/viscosity relationships and proppant flow from a pack. Fluidsystems and techniques for optimized use of curable RCP's are identified, andgel breaker requirements are presented. Compressive strengths obtained underfield conditions generally were much lower than commonly reported. Background The use of plastic materials for sand consolidation in producing wells datesback to 1945, when a phenolic resin was used. Since then, use of variousmaterials, including phenolic, furan, and epoxy resin systems, has beendescribed for various sand-control applications. In 1975, the application ofcurable RCP with a phenolic-based system was patented. Literature pertaining tothe use of plastic materials to control sand production has focused on gravelpacking and sand control. During the last decade, proppant production fromhydraulically fractured wells has increased. One reason is the use of higherproppant concentrations during the treatment. To control this proppantconcentrations during the treatment. To control this proppant productioneconomically, the use of curable RCP has grown proppant productioneconomically, the use of curable RCP has grown from novelty status to standardpractice. During the recent growth of RCP application, conductivity, compressive strengths, and general effectiveness have been considered, but someareas of their application remain relatively unexplored. These areas includethe RCP's effect on the fracturing fluid, the fracturing fluid's effect on the RCP, and the amount of bonding strength required to hold the cured RCP in aproducing fracture. The objective of this research was not to generate fractureconductivity data or proppant crushing, but to provide better understandingbetween the interactions of fluid and RCP. In addressing these issues, werealized that common fracturing fluids and conditions influence the resultingstrengths of cured, consolidated RCP. A better understanding of proppantconsolidation was desired because the fluid and curing conditions of RCP affectstrength. Therefore, this paper discusses the RCP's effect on fluid rheology, the relationship of fluid to RCP strengths, the theoretical study of required RCP strengths to prevent proppant flowback, and experimental measurements toestablish minimum required strengths. Two general methods are now used duringfracturing treatments to consolidate proppant. The most widespread method isthe use of curable phenolic resins precoated on the proppant. In this case, products are manufactured and delivered to location. Two curable phenolic RCPproducts were evaluated in this study: RCP-A normally contains 4% resin and RCP-B normally contains two layers of resin, 2 % precured followed by 2 %curable resin. A new approach is an on-site coating method where requiredmaterials are to the fluid and allowed to coat the proppant during pumping. This system, RCP-C, uses an epoxy-based resin system. The concentration resinused in this system can be varied to adjust the compressive strength of theconsolidated proppant. A precured similar to RCP-A was used and is called RCP-D. RCP Effect on Fluids The influence of RCP on fluid rheology related to crosslink time andviscosity was examined. The effect of RCP on breakers used oil to obtain acontrolled reduction of the fluid's viscosity also was examined. The first testseries examined the influence of RCP-A on the ambient-temperature fluidcrosslinking rate. In these tests, aluminum-, titanium-, and boron-crosslinkedfluids were examined to evaluate acidic, neutral, and basic fluid systems. Table 1 gives the times to crosslink to a "strong" state. From thesefluids tested, we concluded that RCP-A did not significantly influence thecrosslink rate of these fluids. The RCP effect on fluid viscosity was examinedat 170F for a linear gel and a titanium-crosslinked fluid. For evaluating theinteraction of RCP and base gel viscosity, a 100-lbm/1,000-gal solution ofhydroxypropyl guar (HPG) was monitored for I hour at 170F. Because solidproppant usually is not used directly in the Fann Model 50 TM viscometer, theinfluence of RCP on viscosity was determined by mixing either RCP-A or RCP-B at6 lbm/gal in the water used for preparing the gel and then removing the solidsbefore gelation. Because the water-soluble gel most likely would be influencedby water-soluble components from RCP-A or RCP-B. we decided that this techniquewas a reasonable experimental approach. The gel mix water was exposed for 24hours to RCP-A or RCP-B at ambient and 170F temperatures. In anotherexperiment, RCP-A was allowed to cure in air at 170F and then was exposed towater for an additional 24 hours at 170F to determine whether the cured RCP-Awould affect the break properties. Table 2 shows the results of these tests. The procedures described above were repeated with a 50-lbm/1,000-gal solutionof HPG. In this case, the base gel was crosslinked with a titanate crosslinkerbefore the viscosity profile was run for 1 hour at 170F. Table 2 shows thesedata. profile was run for 1 hour at 170F. Table 2 shows these data. Included inthis data set is an experiment where dust collected from pneumatic transfer of RCP-B during a south Texas fracturing treatment was added directly to thecrosslinked fluid. We concluded that the chemical effects on base gel from RCP-A or RCP-B are minimal but that the titanate-crosslinked system viscositypotentially could be reduced by 50% under these test conditions. potentiallycould be reduced by 50% under these test conditions. SPEPE P. 343

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. Introduction As Saudi Arabia increases their demand for natural gas inside the Kingdom, ongoing reservoir targets are moving increasingly to more challenging reservoirs which exhibit low permeability of <0.01 md. Reservoir pressure ranges from low or can be extremely high (11–13,000 psi) and the high temperature makes obtaining reservoir data increasingly difficult due to tool limitations. Two particular formations which have recently received attention is the Sarah and Mid Qusaiba formation. These two reservoirs have been penetrated over 25 times in Ghawar and western Rub' Al Khali areas by Saudi Aramco and the International Oil Companies. Reservoir quality is typically moderate to poor (5–15% porosity); natural fractures are thought to significantly enhance deliverability in wells. Recently hydraulic fracturing was included in the testing of these formations which resulted in short term rates of 3–5 mmscfd. Hydraulic fracturing these formations are increasingly challenging due to mechanical limitations on the completion assembly and surface equipment. Maximum surface pressure limitations of 15,000 psi with a maximum bottom hole pressure limitation required the use of 12.3 lb/gal sodium bromide (Nabr) brine. Heavy brines have been successful in the deep Gulf of Mexico frac packing however they have never been applied to a tight gas reservoir. Development of this fluid was targeted to local material resources, fluid stability at 375º F temperature, proppant transport capability, and minimal formation damage. The new fluid was extensively tested to ensure it would perform as required in the field.

Results of recent field trials with a newly developed fracturing-fluid system and liquid surface-modification additive for coating proppant are presented in this paper. The work was performed in the Underpressured Fruitland Coal (UFTC) gas reservoir in the Northern San Juan Basin of Colorado and New Mexico. This new technology has influenced production in the region. Data of the test-well population are compared to the coal gas and water production from the reservoir. This study identifies and applies the new fracturing system technology for improving production. The results of this study provide information that may apply to other coal-gas reservoirs. The study group of wells uses hydraulic fracturing treatments consisting of a new low polymer loading crosslinked fluid system with a proppant surface-modification additive. The fluid system has increased crosslinked-fluid viscosity, requiring a lower gelling-agent concentration. A liquid additive that coats the proppant and increases its surface adhesion is added in the blender tub during the treatment. The surface friction between the coated proppant grains resists high flow rates during cleanup. Modifying the proppant also influences the migration behavior and blocking effects of fines (coal and precipitates) within the propped fracture.