Summary Proppant flowback from hydraulic fracturing is widespread and costly due to erosion and/or blockage of producing hydrocarbons as proppant may accumulate downhole. Several strategies have been applied to avoid or minimize proppant flowback, such as treatment optimization to maximize pack stability, resin-coated proppant, limiting drawdown, or letting it flow to deal with the consequences later. Another strategy to avoid proppant flowback is to install sand control equipment integrated into a sliding sleeve device (SSD) as part of the completion string. Although the presence of sand control equipment can mitigate the problem, it raises concern about erosion during fracturing. Although some installations have been successful, one is known to have experienced sand control failure. This study aimed to understand the effect of hydraulic fracturing on the erosion of completion equipment with an objective of improving the design to, as much as possible, prevent erosion failure. Computational fluid dynamics (CFD) was used to evaluate the root cause and identify more robust design solutions. The first step was to identify the most probable causes of sand control failure during multistage fracturing (MSF) in openhole (OH) horizontals. The as-is completion was then modeled, along with the screen, SSD, fracturing port, and OH isolation packer. Because the fracture location between two packers is unknown, and the fracturing port was located between multiple screen/SSD assemblies, annular flow across the assembly in both directions was considered. State-of-the-art CFD simulations were then performed on the installed design using actual flow conditions (rates, slurry properties, treatment time) from the failed installation. A new quasidynamic mesh (QDM) methodology was developed, which yielded more realistic (albeit still conservative) erosion-depth predictions. The results revealed areas for improving the design of key components of the 10-ksi-rated system, and CFD was rerun to confirm erosion resistance targets. Design modifications were implemented, and improved products were then manufactured and field tested. For a new 15-ksi design, particle–particle interaction was added to the CFD analysis. The results of the CFD analysis and field test are presented herein.
Summary To prevent or minimize problems associated with water coning in horizontal oil producers, inflow control devices (ICDs) are installed along the wellbore to better equalize the toe-to-heel flux. Nozzle-based ICDs are popular because they are easy to model accurately, virtually viscosity independent, and easy to install at the wellsite with many settings. Nozzles can be installed either in the wall of the base-pipe (radial orientation) or in the annulus between the base-pipe and housing (axial orientation). The advantages of the former are smaller maximum-running outer diameter (OD) and no need for a leak-tight, pressure-rated housing. One disadvantage is the high exit velocity that raises concern of erosion or erosion-corrosion of the base-pipe. To overcome this disadvantage, a new nozzle has been developed with a novel geometry that reduces the exit velocity approximately tenfold compared with a conventional nozzle for the same pressure drop and flow rate. Computational fluid dynamics (CFD) was used to first fine tune the design to meet strict erosion-corrosion prevention requirements on the wall shear-stress downstream of the nozzle for both production and (acid) injection directions, and then to develop flow-performance curves for four different nozzle “sizes” that vary in their choking ability, thereby allowing many different settings per joint at the wellsite. Full-scale prototype manufacturing and flow-loop testing were then performed to validate the CFD flow-performance predictions and to demonstrate mechanical integrity and erosion resistance for high-rate production and injection. The results, as presented herein, demonstrate a robust and commercially viable ICD design that has predictable flow performance using CFD, minimizes erosion and erosion-corrosion in either direction, minimizes running OD, simplifies the housing design, and allows easy installation at the wellsite with 34 settings per joint. Also discussed are two new advantages over other ICDs that were not anticipated in the original development.
Summary Interest is high in a method to reliably run single-trip completions without involving complex/expensive technologies (Robertson et al. 2019). The reward for such a design would be reduced rig time, safety risks, and completion costs. As described herein, a unique pressure-activated sliding side door (PSSD) valve was developed and field tested to open without intervention after completion is circulated to total depth (TD) and a liner hanger and openhole isolation packers are set. A field-provensliding-sleeve door (SSD) valve that required shifting via a shifting tool run on coiled tubing, slickline (SL), or wireline was upgraded to open automatically after relieving tubing pressure once packers (and/or a liner hanger) are set. This PSSD technology, which is integrable to almost any type of sand control screen, is equipped with a backup contingency should the primary mechanism fail to open. Once opened, the installed PSSDs can be shifted mechanically with unlimited frequency. The two- or three-position valve can be integrated with inflow control devices (ICDs) (includes autonomous ICDs/autonomous inflow control valves) and allows mechanical shifting at any time after installation to close, stimulate or adjust ICD settings. After a computer-aided design stage to achieve all the operational/mechanical requirements, prototypes were built and tested, followed by field installations. The design stage provided some challenges even though the pressure-activation feature was being added to a mature/proven SSD technology. Prototype testing in a full-scale vertical test well proved valuable because it revealed failure modes that could not have appeared in the smaller-scale laboratory test facilities. Lessons learned from the first field trial helped improve onsite handling procedures. The production logging tool run on first installation confirmed the PSSDs with ICDs opened as designed. The second field installation involved a different size and configuration, in which PSSDs with ICDs performed as designed. The unique two- or three-position PSSD accommodates any type of sand control or debris screen and any type of ICD for production/injection. The PSSD allows the flexibility to change ICD size easily at the wellsite. Therefore, this technology can be used in carbonate as well as sandstone wells. Wells that normally could not justify the expense of existing single-trip completion technologies can now benefit from the cost savings of single-trip completions, including ones that require ICD and stimulation options.
Summary Sand control screens are installed with an internal string (wash pipe) as required which, among other functions, provides a circulation path. In long horizontal wells, running a wash pipe consumes considerable rig time and may limit the ability to reach target depth. In cases in which fluid losses are experienced after screen installation, isolating the open hole with a fluid-loss control valve can be prolonged. This paper describes a wash-pipe-free solution for screen installation using a check-valve inflow control device (CV-ICD). ICD screens are commonly used to delay/restrict the influx of unwanted fluids such as gas or water. The wash-pipe-free solution integrates a check valve with the ICD to prevent outflow through the screen during circulation and allows inflow through the screen when placed on production. This solution uses a check ball that seals against the ICD during circulation but falls back on a porous retainer plate during production. The check ball and retainer plate can be dissolved by spotting a reactive fluid inside the screen or made to erode over time with production. Laboratory testing yielded the following results: the ICD with the check ball was shown to seal up to 5,000 psi; the check ball and retainer plate can be dissolved by a reactive fluid, which can be tailored to bottomhole temperature and the required time of dissolution; and the pressure activation test demonstrated that the maximum differential pressure to seat the ball was less than 5 psi. This CV-ICD solution has been applied worldwide in more than 35 wells, most of which were targeted to avoid running a wash pipe. However, in two wells the technology was successfully used to set openhole packers with a 5,000-psi setting pressure. In this paper, we present the wash-pipe-free ICD screen installation with a dissolvable check valve and the capability of setting a hydraulic packer without a wash pipe or intervention in the open hole. The novel contribution presented herein is the ability to integrate a ball and cage to existing nozzle-based ICDs by using dissolvable material to achieve the preceding results in this application.
Proppant flowback from hydraulic fracturing is widespread and costly due to erosion and/or blockage of producing hydrocarbons due to proppant accumulation. One remedy is to install sand control equipment integrated into a sliding sleeve device (SSD) as part of the completion string, which raises concern about erosion during fracturing. While some installations have been successful, at least one experienced sand control failure. Computational Fluid Dynamics (CFD) was deployed to evaluate the root cause and identify more robust designs, as presented herein. Firstly, we identified the most probable causes of sand control failure during multistage fracturing (MSF) in openhole (OH) horizontals. State-of-the-art CFD simulations were then performed on the installed design using actual flow conditions (rates, slurry properties, treatment time) from a failed installation. The static CFD methodology in an initial undeformed geometry proved to be ultra-conservative, so a new quasi dynamic mesh (QDM) methodology was developed, which yielded more realistic (albeit still conservative) erosion-depth predictions. The results revealed areas for improving the design of key components, and CFD was re-run to confirm erosion resistance targets. The modifications were then implemented for a field trial. Since frack location between two openhole packers is unknown, and the frack port is located between multiple screen/SSD assemblies, one must consider annular flow across the assembly in both directions. Accurate CFD predictions of erosion of completion components versus time during MSF in OH proved challenging. The quicker static methods were useful in ruling out some components as problem areas, such as the sand control media, but proved overly conservative on other key components. The QDM methodology gave more realistic results and indicated that erosion depths in specific locations could be deep enough to possibly cause sand control failure. To reduce the erosion risk, such components were modified, and the result was a reduction in predicted erosion depths to acceptable levels. A safety factor was already built into the predictions because of two key conservative assumptions: ignored initially were 1) particle-particle interaction and 2) erosion of the reservoir wall. The former was further investigated. While waiting for the field trial results, the main conclusion thus far is that CFD is a valuable tool for diagnosing erosion failures and improving equipment design. However, it’s essential to use a methodology that realistically captures downhole conditions. Presented herein is a more robust design of a screen/SSD assembly for proppant flowback control, as well as an improved CFD methodology for diagnosing sand control failures during MSF and for identifying design improvements of completion equipment. Furthermore, the inherent challenges of controlling proppant flowback without causing erosion or flow blockage of hydrocarbons are discussed.
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