The results of a series of proppant transport surface tests (PTSTs) were used in conjunction with Eulerian multiphase-computational fluid dynamics (EMP-CFD) modeling to develop an engineering model of proppant distribution. The PTSTs were carried out to evaluate proppant placement through perforated casing. In these tests, sand slurry was pumped at realistically high flow rates through perforated casing and the distribution of sand and slurry from each perforation cluster was observed. The tests show that gravitational settling in horizontal casing, proppant slip past perforations and the visco-elastic properties of slickwater fluids strongly affect the distribution of proppant from the heel to the toe of the completion. The EMP-CFD modeling was used to estimate the gravitational settling of sand in fully-developed turbulent slurry flow in horizontal casing as a function of casing velocity. A survey of 36 calculations was carried out to generate tables of sand concentration in a cross section through the casing as a function of flow rate and particle size. A single-phase CFD analysis showed how sand exiting each perforation is taken from a limited ingestion area which is proportional to the ratio of flow through the perforation to total flow in the casing. A detailed EMP-CFD analysis of flow through single perforations showed how sand slips past the perforation. The results of 28 EMP-CFD calculations provided slip factors as a function of particle size, casing flow velocity, and perforation flow velocity in straight and angled perforations. The EMP-CFD settling tables and a parameterization of the slip factors were integrated into an engineering model. The model predicts the distribution of slurry and sand through each perforation based on the proppant size, perforation phase angle, and pump rate. The engineering model was used to predict the sand distributions observed in the PTSTs. The PTSTs were conducted with a range of sand sizes and with low-viscosity friction reducing polymer (FR) additives, while the EMP-CFD analysis assumed water. A weight factor is introduced in the settling model to account for the increased dispersion of sand in water with low viscosity FR and to match the observed sand distributions in the PTSTs. The observed slip of 100 Mesh and 40/70 Mesh sand is consistent with the EMP-CFD calculations in water. The model reflects the PTST observations that fine sand is distributed relatively uniformly throughout the length of a perforated completion while coarser sand tends to slip past the heel perforations and concentrate on the bottom towards the toe of the completion.

This is believed to be the world's first two attempts, both successful, to replicate multi-cluster hydraulic fracturing at surface to better understand not only proppant transport and placement by cluster, but a host of other items of interest such as perforation erosion. With due recognition and compliments to all the good theoretical studies conducted and published by the academic community, it seemed that actual physical tests could be a valuable contribution to the industry activity. Both 8 cluster (6 shots per cluster) and 13 cluster (3 shots per cluster) tests were completed at 90 BPM injection rates at approximately 1,500 psi initial differential pressures. Both tests were conducted in 5.5" 23#, P-110 casing, with assembly lengths of 191 feet and 216 feet respectively. Water, Water plus Friction Reducer, 100 mesh sand and 40/70 mesh sand were utilized on these highly instrumented tests with each cluster having its own individual tank to capture fluids and proppants as they exited the perforation clusters. Perforation hole size changes, fluid level data, and proppant masses were captured after each test along with all the frac fleet data and pressure gauge data at each cluster. How the tests were safely and successfully executed will also be discussed. These tests led to subsequent tests with 15 perforation clusters with different charge designs and perforation orientations in a project with a larger number of operators participating. Predictive software based on computational fluid dynamics was also developed as an outcome of the project learnings and actual physical measurements. The key benefit of these tests is that all the data was physically measured and not subject to interpretation, therefore providing solid data for subsequent model calibration and predictions. Validity and shortfalls in the standardly used orifice flow equations was also the subject of the studies and will be discussed. Learnings about perforation erosion and impacts of different proppant sources as well as fluid velocities occurred.

Reservoirs with bottomhole temperatures (BHT's) in excess of 250°F [121°q and penneabilities of less than 1.0 md are commonly encountered in drilling and completing geothennal and deep gas wells. Successful stimulation of these wells often requires the use of massive hydraulic fracturing (MHF) treatments. Fracturing fluids chosen for these large treatments must possess shear and thennal stability at high BHT's.The use of conventional fracturing fluids has been limited traditionally to wells with BHT's of 250 0 P [121°q or less. Above 250°F [121°q, high polymer concentrations and/or large fluid volumes are required to ,maintain effective fluid viscosities in the fracture.However, high polymer concentrations lead to high friction pressures, high costs, and high gel residue levels.The large fluid volumes also increase significantly the cost of the treatment. Greater understanding of fracturing fluid properties has led to the development of a crosslinked fracturing fluid designed specifically for wells with BHT's above 250~F [121°q. The specialized chemistry of this fluid combines a high-pH hydroxypropyl guar gum (HPG) solution with a high-temperature gel stabilizer and a proprietary crosslinker. The fluid remains stable at 250 to 350°F [121 to 177°q for extended periods of time under shear. This paper describes the rheological evaluations used in the systematic development of this fracturing fluid.In field applications, this fracturing fluid has been used to stimulate successfully wells with BHT's ranging from 250 to 540°F [121 to 282°q. Case histories that include pretreatment and posttreatment production data are presented.

A large series of experiments was performed to measure the downhole rheology of various quality foams of Carbon Dioxide, Nitrogen and mixtures of the two with aqueous phases consisting of non-crosslinked and crosslinked polymer solutions. Traditional methodology for rheological data analysis, used in small scale horizontal pipe experiments, could not be applied to these large scale vertical experiments because of the interrelation between friction and hydrostatic pressure drops. Therefore, a two-step methodology was developed which consisted of obtaining friction factors from primary data by solving a two-phase vertical flow equation. Then a rheological model was applied to describe the friction factor behavior. A new variable, the specific volume expansion ratio, was found the most useful to correlate friction factor data. The obtained correlation, named Volume Equalized Power Law model, is suitable to represent foam rheology. Model parameters are given for various liquid formulations. A calculational procedure is presented, applicable in field conditions, where a varying quality is always evident.

Reservoirs with permeabilities of less than 1 md and bottomhole temperatures in excess of 250°F are commonly encountered in the continuing search for hydrocarbons. Successful completion of these wells often requires the use of Massive Hydraulic Fracturing (MHF) treatments. The fracturing fluids used in MHF treatments are frequently subjected to excessive shear and prolonged exposure at high bottomhole temperatures. Early fracturing fluids proved unsuitable for these MHF treatments due to a rapid loss of viscosity at high temperatures. As a result, narrow fracture widths, excessive fluid loss and poor proppant transport occurred. Cool-down pads, increased polymer concentrations and delayed polymer hydration systems were employed in an attempt to improve the MHF treatment success ratio. A laboratory study was undertaken to develop a more efficient high temperature fracturing fluid. Rotational and pipe viscometers were used to evaluate thermal and shear stabilities under reservoir conditions. Fluid loss testing measured the effectiveness of fluid leakoff control. Fluid breakout testing ensured a controlled loss of viscosity and minimal proppant pack gel residue. As a result of this study, a more efficient high temperature fracturing fluid was developed. This paper presents laboratory data comparing the thermal stability, shear stability and fluid loss control of the High Temperature Gel (HTG) with those of a conventional titanate crosslinked gel. Field case histories axe presented to demonstrate the efficiency with which the HTG system has been used to successfully stimulate low permeability gas wells with bottomhole temperatures in excess of 250°F.