Enhanced oil recovery (EOR) schemes utilizing CO2 and water injection often experience significant problems and challenges with short circuiting of CO2 gas and water between injectors and producers, thereby leaving significant oil behind. Presented herein is the description and results of a field trial of new downhole flow control technology designed to provide autonomous inflow control of produced fluids from each zone in multi-zone wells. The new technology deployed involves integrating an autonomous inflow control valve (AICV) and a conventional (passive, non-autonomous) inflow control device (ICD) into a unique 3-position "sliding sleeve", shifted by coil tubing, to allow performance comparison between the two different inflow control devices as well as multiple flow control settings of each type. The AICV was designed (and lab tested) to selectively choke back or shut off flow of free CO2 gas and also high watercut (>99%), thereby significantly improving reservoir sweep and yielding higher oil production. The AICV opens or closes autonomously depending on sensed properties of wellbore fluids. Prior to installing the advanced completion, the multi-zone (vertical) trial well was extensively characterized using PLT and other log data, which was then inputted into a commercially available computer model to help design the AICV and ICD settings. The field trial was designed to evaluate the use of flow control in the EOR scheme over a wide range of flow rates and also to compare the two different flow control technologies at different settings within the same wellbore and reservoir condititions. This paper presents the results of the world's first field trial of the AICV in a Water and CO2 injection scheme, and the world's first comparison with conventional ICD technology in the same well. In addition to lab tests, the early field trial results of the advanced flow control completion are compared with historical production and PLT data where the zones were comingled (without any downhole flow control). A performance comparison of AICV versus conventional ICD, along with conclusions, implications for other wells in the same field and other fields, and lessons learned, are all presented herein.
Events such as hydraulic gradients in the horizontal completion, geologic and fluid variations in the reservoir and well placement issues can produce very poor steam conformance in the Steam Assisted Gravity Drainage (SAGD) process. Operators have implemented many strategies in an effort to address the issue. Simultaneous injection in inner tubing and annulus space or dual-tubing completions are commonly used in SAGD wells to provide controllable injection and production from the heel and toe regions of the horizontal well pair but this does not guarantee both uniform and efficient performance. This paper presents a study of a hybrid of two technologies to improve both conformance and economics of this thermal process. Recent work suggests that using Proportional-Integral-Derivative (PID) feedback to control the steam injection can lead to improvements in SAGD performance and conformance. The feedback control is applied to each steam injection point in the horizontal well pair. Injection at these control points is regulated by a PID feedback controller monitoring temperature differences between injected and produced fluids in order to both enforce a specified subcool and to achieve uniform production along the entire length of the producer. PID feedback control can be practically and inexpensively implemented in the field with current technology. Inflow or injection control devices (ICDs) can also improve SAGD performance. ICDs (or FCDs) can be incorporated in the horizontal completion as restrictive elements to modify the pressure distribution along the length of the wellbore. Among other benefits, properly sized and distributed ICDs can create a more uniform flow profile along the horizontal section of the well, regardless of permeability, formation damage and wellbore location. Furthermore, ICDs on the producer can provide a self-regulating effect to prevent live steam from entering the sand control screen. This paper examines detailed wellbore simulations of a SAGD process in which wells are equipped with a combination of ICD completions and feedback control in order to (i) determine the physical mechanisms (including the dynamic flow paths inside the well and in the near wellbore region), and (ii) outline practical procedures to determine an improved ICD completion and feedback control design. A novel aspect of this work is the inclusion of a revised flow-regime-independent multiphase flow correlation that can predict the pressure drop in horizontal and near-horizontal wells. Results presented in this paper should aid reservoir simulation engineers in both the design and optimization of steam injection in a SAGD well pair.
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.
Ever since horizontal drilling became prominent decades ago, it has been the goal of oilfield operators to find an effective mechanism for controlling the toe-to-heel flux into the production liner to delay and/or reduce the inflow of unwanted fluids such as water, gas and steam, in order to maximize sweep efficiency and oil production/recovery. Inflow Control Devices (ICDs) are basically flow restrictors installed along the completion string to alter the pressure drawdown on the reservoir by choking back the high permeability/high mobility zones while allowing more influx from the lower permeability/lower mobility zones. In steam assisted gravity drainage (SAGD) production wells the primary goal is to operate at lower subcool while minimizing live steam production. The pace of ICD technology adoption has accelerated amongst the operators since its benefit was made prominent in the Surmont field (Stalder 2012). PetroChinaCanada (formerly known as Brion Energy) recognized the technical opportunity and commenced implementation of an ICD technology trial at its MacKay River asset. The technology selection, ICDs sizing and performace prediction was conducted in 2013 (Becerra et al). In 2014 two SAGD production wells, each located on different pads, were selected to evaluate if ICDs could have a beneficial impact on performance. The purpose of this paper is to present preliminary results of the two ICD producer wells which, as of November 2017, have shown superior performance to their non-ICD neighboring wells after about 6 months of production.
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.
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