Production decline in acid-fractured reservoirs result from the elastic, plastic, and creeping response of highly confined vertical stresses that can destroy the conductive channels created by the acid. This paper introduces a novel, highly viscous acid system having the potential to suspend proppant and perform simultaneous acid and proppant fracturing treatments. During production, impure carbonates tend to decrease productivity as quartz and other minerals migrate, leading to channel closing and/or collapse. Conventionally, acid fracturing treatments are performed by fracturing without proppant followed by different acid stages, including gelled acid. The idea of proppant-fracturing-acidizing (PFA) system entails fracturing in a single stage operation, although to avoid post-treatment plugging of the propped fractures the application of the process would be limited to very clean carbonates. This paper describes PFA fluid prepared by emulsifying hydrochloric acid (HCl) in the internal phase using diesel as the external phase. PFA offers distinct advantages compared to conventional acid systems, namely high viscosity to carry proppant, simultaneously acid-etching the rock, while attaining deeper live acid penetration. Another potential advantage is lowering operational time because mixing can be performed on-the-fly. Preliminary experimental studies have been carried out to investigate the performance of PFA fluid and validate its applicability to perform simultaneous acid and proppant fracturing. PFA was prepared at various HCl concentrations and tested up to 28%. PFA fluid viscosity under different shear rates was measured at high-pressure/high-temperature (HP/PT). It exhibited viscosity as high as 2424 cp at 100°F and 300 cp at 300°F at 50 1/s shear rate. The oil external nature and the stability of the PFA fluid were examined using HP/HT autoclaves at 300°F. The effectiveness of corrosion inhibitors in PFA fluid was determined at 300°F. Static proppant settling tests showed that PFA fluid has good proppant carrying capacity at different particle loadings. After spending PFA fluid in carbonate, the viscosity was reduced significantly, exhibiting breaker-free cleanup. Carbonate reservoirs having closure stress of more than 5,000 psi could be propped to enhance conductivity using PFA system. Enhancing the stimulated reservoir volume could be plausible using PFA system as a single-fluid treatment option, particularly if acid leakoff control and diversion, deeper penetration, and acid and proppant fracturing can be simultaneously implemented.
Water sensitive formations, mature fields, and relatively depleted formations can require complex fluid formulations using specific bottomhole assemblies (BHAs) and underbalanced guns fired to help minimize formation damage. Results have demonstrated that, in many cases where standard procedures were followed, production decreased and such procedures were not always completely effective. This phenomenon can be attributed to formation characteristics, such as kaolinite, smectite, silica incrustations, tertiary precipitations, pH changes, clay swelling, and others. Relative permeability modifiers (RPMs) are being formulated and used within the oil industry to help mitigate such issues. Physically, the objective is to decrease the relative permeability to water without any (or minimum) modifications of relative permeability to oil. Basically, this methodology can be applied in water wet formations without oil permeability modifications. A standard procedure was executed in four wells and two different formations to prove this technique. The technique involves using a standard BHA to clean and condition the well, after having selected the zone where the perforating guns will be fired. A specific formulation of RPM treatment is placed inside the casing using a balanced fluid placement technique in front of the section to be shot. This type of fluid has no salinity sensitivity and very low viscosity (less than 4 cp). After placing the RPM fluid, tubing must carefully be pulled out of the hole (POOH) to avoid disturbing and damaging this temporary plug. Guns are run into the hole(RIH) to the selected zone to be perforated after spotting the RPM and then fired, squeezing the system into the desired formations through the casing. The pressure limit must be related to the casing integrity and no more than 1,500 psi as closure pressure (10 min stabilization trend) is measured at surface, and then the final BHA run to begin production. The primary objective of this paper is to present a non-damaging fluid that can be pumped (or gravity injected) through recently open perforations, reaching casing closure pressure, and changing nearby water permeability, without causing any completion fluid invasion into the formation or induced damage. This process can put the well into production immediately, without any additional cleaning fluid necessary for the removal of the RPM fluid from the formation. The treated wells experienced production with zero damage to formations.
The infinite conductivity theory to enhance production was introduced to the industry around 1971. Exploration from the 1970s to the 1990s focused on high permeability formations. The unconventional reservoirs and tight formations were left behind until new technology could enable hydrocarbons to be produced in economical manner. Operators seek methods to both increase initial production and slow the decline rates. This paper describes the infinite conductivity technique to help to enhance production in unconventional reservoirs and tight formations. The advanced pillar fracturing technology was evaluated as an infinite conductivity technique using binding agents to help generate stabilized proppant pillars to create voids and conduits inside the induced fractures during fracture stimulation treatments. The pillars remain stable at reservoir pressure and temperature to help to prevent excessive fracture closure during drawdown. The methodology uses specific surface equipment designed to establish pulsing of slurry and clean fluid segments during proppant placement. This methodology is combined with liquid resin technology to help to prevent proppant and fines migration, as well as reduce proppant embedment that would allow blockage of the conduit spaces. Consequently, the new technology reduces the necessary proppant volume pumped into the formation, thereby reducing the potential of proppant screenout. Mechanical stress on the packed fractures is significantly greater during production when drawdown pressures are maximized and reservoir pressures begin to decline. These two pressures can lead to greater stresses on the proppant after closure. High closure stress also applies pressure to the proppant during production; consequently, the proppant has an increased tendency to crush. Proppant diagenesis is possible and can consequently contribute to reductions in conductivity. However, the application of liquid modified resin creates a film on the proppant surface, resulting in significant reductions in proppant reaction with the formation rock and fluid. This technique reduces diagenesis and helps to control fines generated from crushing that could plug the proppant pack and reduce conductivity. Modified liquid resin also increases pillar strength by creating a film on proppant grains. The application of different shear stresses enhances and stabilizes the strength of the pillar and keeps the newly created conduits open to flow. This paper presents a case history that shows that the production from a well stimulated without modified liquid resin declines significantly more than another well treated with resin-coated proppant. This paper presents a novel infinite conductivity technique that uses a pulsed proppant fracturing process to provide enhanced and sustained production over conventional treatments. The proppant pulsing process helps to create proppant pillars with open flow paths that are highly conductive and can enable almost infinite conductivity.
Increased exploration and development of unconventional reservoirs is one of the main contributing factors to increased hydraulic fracturing activity. The primary aim of hydraulic fracturing is to provide a means for hydrocarbon productivity in tight formations at economic levels. The use of natural sand in high stress zones (greater than 5,000-psi closure stress) is known to lead to increased fines generation and subsequent migration. Thisresults in a detrimental decrease in hydrocarbon productivity, which reduces the value of and could even negate the purpose of conducting hydraulic fracturing. Manmade proppants are able to withstand elevated closure stress environments and have been a widely accepted means of overcoming the limits of natural sand as a propping agent for fracturing operations in medium to high stress environments. A novel engineering procedure using natural sand to withstand higher stresses in proppant fracturing operations was evaluated both in the laboratory and at field scale. This methodology successfully demonstrated the ability of natural sand tokeep fractures open and support formation stresses while simultaneously allowing access to a highly conductive path typically achieved using intermediate- to high-strength manmade proppants in the associated stress regime. This technique also has shown to drastically reduce fines generation and migration along propped fracture geometry, maintain acceptable conductivity of the fracture throughout the stress process, and minimize diagenesis effects typically observed on existing proppant materials. This novel technique can be used to increase the conductivityof hydraulic fractures in unconventional reservoirs. The paper describes a methodology to increase the strength range of natural sand to enable its use in high stress zones without risk of losing fracture conductivity resulting from fines migration. A laboratory scale model was designed to simulate the high temperatures and stresses present at reservoir conditions. The associated model showed natural sand can be used in elevated reservoir conditions up to 12,000 psi stress, resulting in increased hydrocarbon production and reduced costs as well as providing new opportunitiesfor economic fracturing applications in conventional and unconventional reservoirs.
There are sand formations that do not have a minimum contact pore space cemented. Typically, these sands have very low toughness, high permeability, and high porosity. Such factors allow fines and solids migration. The consequence of this scenario is the increase of workover interventions and equipment damage/erosion caused by sand flow, thus resulting in increasing cost, lost time, and insufficient production. Drilling these formations is challenging. Taking core samples to perform rock mechanic tests in a laboratory is also a difficult task. Additionally, there are cases where wells do not have sonic dipole surveys to help with evaluations. Usually, the samples are not uniform, have cracks, are broken, or completely dispersed, making their application in rock mechanic characterizations impossible. The presented methodology applies the Mohr-Coulomb cycling test for the first time to actually process step-rate, fracturing, and falloff tests. Field tests using this technique have shown good correlations and obtained reliable curves for hydraulic fracturing simulators. A package of rock mechanics equations described in the oil industry are evaluated and tested in field scale. Many times, engineering teams must have a source of equations which can easily calculate required parameters to be used for sieve analysis, gravel pack, and fracture pack projects. Basically, the methodology is reliable because of the equations of theoretical soil mechanics (Terzagui 1943), Mohr-Coulomb, and field practices of determinations of minimum in-situ stresses and overburdens. After field test confirmations, the objective of this matter is to present correlations of Terzagui (1943) and Mohr-Coulomb equations to be used during gravel, fracture pack, and hydraulic fracturing operations. The methodology has an important presence during the study to help minimize risk during these jobs and obtain good approach simulations because, as previously discussed, this type of sandstone makes obtaining formation samples challenging. Equations can provide a good number of useful calculations and help reduce operational risk when performing these types of well completions or treatments.
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