Deng, Guijun (,Baker Hughes, a GE company) | Kendall, Alexander (,Baker Hughes, a GE company) | Cook, Christopher (,Baker Hughes, a GE company) | Wakefield, John (,Baker Hughes, a GE company) | Maenza, Frank (,Baker Hughes, a GE company) | Tom, Andy (,Baker Hughes, a GE company) | Knebel, Mark (,Baker Hughes, a GE company)
This paper is a continuation of a previous work, SPE191734 (
Three factors primarily contributed to its successful qualification. First, new backup technology eliminated traditional design limitations imposed by conventional manufacturing and enabled us to design and print a backup system with ultra-expansion capacity and superior conformability. Second, an internally developed polymer that exhibits great elongation and extrusion resistance played a key role in holding the 15,000 psi pressure reversals at 350F in the ultra-expansion states. Finally, a state-of-the-art design process seamlessly integrated design, material characterization, design optimization, and test validation, enabling rapid failure diagnosis and design iterations to ensure rigorous customer requirements were satisfied. This integrated process reduces development costs and shortens time to market.
An ultra-high expansion openhole HPHT packer was developed as a result of advances in Additive Manufacturing technology, polymeric materials, and a holistic design process. Physical test validation demonstrated:
15,000 psi pressure reversal and 15 minute hold at 350°F. Displacement of 0.5 in and 15,000 pressure reversal at 350°F. Elastomer element system remained in good visual condition in post-test inspection.
15,000 psi pressure reversal and 15 minute hold at 350°F.
Displacement of 0.5 in and 15,000 pressure reversal at 350°F.
Elastomer element system remained in good visual condition in post-test inspection.
This is the industry's first commercial completion packer with an Additive Manufactured element containment system. It is also the industry's first ultra-expansion packer to demonstrate HPHT capability.
This paper presents the rapid development of a high expansion retrievable V0-rated bridge plug that effectively leveraged engineering simulation and additive manufacturing to design, optimize, and qualify the new plug in accordance with the ISO14310 and API11D1 standards. This technology was mobilized for deployment into a customer well within less than 12 months.
For this project, a major Norwegian continental shelf (NCS) operator required a high expansion wireline retrievable bridge plug with a small outside diameter (OD) that was capable of gas-tight zonal isolation in 7 in. tubing while meeting the ISO14310 and API 11D1 V0 classifications. To address this challenge, several design concepts were developed using computer-aided design (CAD) and simulated using finite element analysis (FEA) to determine the optimal design and to establish the design factor of safety. Initial prototype testing showed unexpected failures of the mechanical backup system as a result of non-uniform loading from the rubber element, which had been assumed to be evenly distributed for the initial FEA. Leveraging FEA to verify the failure mode increased its fidelity and enabled successful generation of alternate solutions with an alternate material, in this case nickel alloy 718. A revised mechanical backup system was manufactured within three weeks using internal direct metal additive manufacturing capability; it was successfully validated within an additional two weeks. The final V0 trials were successfully completed a month later with additively manufactured components, and the technology was mobilized for deployment into the operator’s well within less than 12 months.
The successful design, development, and mobilization of the 7-in. high expansion V0-rated bridge plug within only 12 months demonstrates how FEA modeling and additive manufacturing can be successfully leveraged to reduce development timelines while identifying and producing innovative solutions. Speed to market and the delivery of robust solutions on time are becoming more critical in the cost-constrained oil market; consequently, tools such as FEA and additive manufacturing are increasingly becoming fundamental methods for meeting these new challenges, as demonstrated by the 7-in. high expansion V0 bridge plug project.
This paper shows how leveraging FEA in conjunction with fundamental testing failure analysis can be critical to overcoming technical challenges. Furthermore, combining these capabilities with additive manufacturing can accelerate timelines and increase the probability of project success and operator satisfaction.
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. In the context of elastomers, blistering is surface deterioration caused by gas trying to escape too rapidly from a elastomer and tearing the surface of the material. In the context of steel, blistering is surface corrosion associated with gas adsorption.
In downhole applications, most progressive cavity (PC) pump failures involve the stator elastomer and often result from chemical or physical elastomer breakdown induced by the wellbore environment. Successful use of PC pumps, particularly in the more severe downhole environments, requires proper elastomer selection and appropriate pump sizing and operation. PC pump manufacturers continue to develop and test new elastomers; over time, these efforts have resulted in performance improvements and an expanded range of practical applications. Despite this success, the elastomer component still continues to impose severe restrictions on PC pump use, especially in applications with lighter oils or higher temperatures. The performance of an elastomer in a PCP application depends heavily on its mechanical and chemical properties.
The following topic describes the installation, monitoring, troubleshooting and failure analysis of the Progressive Cavity Pumping systems (PCP) used in the oil and gas industry. Adherence to proper installation procedures for both downhole and surface equipment is key to the successful operation and performance of a PCP system. Given the many different types of equipment available and the number of system configuration alternatives, it is advisable to review the product manuals provided by PCP equipment vendors to obtain detailed installation instructions and system operating information for specific installations. The well-servicing guide books available from some service companies also provide useful information. Well monitoring typically refers to the periodic or continuous measurement of production parameters and evaluation of the pumping system operating conditions.
Elevated-temperature applications can be divided into medium- and high-temperature categories. The medium-temperature category covers deeper-well applications with natural, higher-temperature reservoir conditions ranging from 40 C [104 F] to 100 C [212 F]. Field experience has proved that progressive cavity (PC) pumps can be used successfully in wells producing fluids within this temperature range if the fluid temperatures remain relatively constant. However, to achieve reasonable run lives in such wells, additional attention must be given to elastomer and pump model selection, pump sizing practices, and system operation. The importance of these considerations rises substantially as temperatures increase toward the higher end of this range.
Production of high-viscosity fluids can result in significant flow losses through the production tubing and surface piping. In some instances, the pressure requirements generated because of flow losses can exceed the hydrostatic head on a well. It is critical that system design account for the "worst-case" flow losses, particularly the selection of the pump (pressure rating), rod string (torque capacity), and prime mover (power output). Over the past decade, progressive cavity pump (PCP) systems have become a very popular artificial-lift method for producing heavy oil (API gravity 18) wells throughout the world. Fluid viscosity under downhole conditions can range from a few hundred centipoise to 100,000 cp in these applications, and the production rates also vary significantly although low rates are far more typical.
The packer is a sealing device that isolates and contains produced fluids and pressures within the wellbore to protect the casing and other formations above or below the producing zone. This is essential to the basic functioning of most wells. Packers have four key features: slip, cone, packing-element system, and body or mandrel. The slip is a wedge-shaped device with wickers (or teeth) on its face, which penetrate and grip the casing wall when the packer is set. The cone is beveled to match the back of the slip and forms a ramp that drives the slip outward and into the casing wall when setting force is applied to the packer. Once the slips have anchored into the casing wall, additional applied setting force energizes the packing-element system and creates a seal between the packer body and the inside diameter of the casing. Production packers can be classified into two groups: retrievable and permanent. Permanent packers can be removed from the wellbore only by milling. The retrievable packer may or may not be resettable; however, removal from the wellbore normally does not require milling. Retrieval is usually accomplished by some form of tubing manipulation. This may necessitate rotation or require pulling tension on the tubing string. The permanent packer is fairly simple and generally offers higher performance in both temperature and pressure ratings than does the retrievable packer. In most instances, it has a smaller outside diameter (OD), offering greater running clearance inside the casing string than do retrievable packers. The smaller OD and the compact design of the permanent packer help the tool negotiate through tight spots and deviations in the wellbore. The permanent packer also offers the largest inside diameter (ID) to make it compatible with larger-diameter tubing strings and monobore completions.
The basic system components include the downhole pump, sucker rod and production tubing strings, and surface drive equipment, which must include a stuffing box. However, a PCP installation may also include different accessory equipment, such as gas separators, rod centralizers, tubing-string rotator systems, and surface equipment control devices. The following sections describe the various components of a PCP installation in further detail. Figure 1.5--Cross sections of conventional and modified 2:3 multilobe PC pumps. Figure 1.14--Speed vs. torque characteristics for a squirrel-cage induction motor. This section outlines some auxiliary equipment commonly used with PCP systems. A tag bar or "rotor stop" is normally required to facilitate installation and spaceout of the rod string. Several different tag bar designs are available, but they usually consist simply of a steel rod or bar (approximately 25 mm [1 in.] in diameter) fastened widthwise across the middle of a short (e.g., 0.6 m [2 ft]) perforated tubing pup joint that is threaded to the pump intake. In some designs, the rod is replaced with a steel plate with holes to permit fluid flow. The number and shape of the perforations in the pup joint vary among manufacturers. A large perforated area is particularly important in highly viscous fluid applications to minimize flow losses and to facilitate sand flow to the pump intake. The pump vendor usually supplies a tag bar joint with the PC pump. Although the tag bar pup is usually the bottom component of the tubing string in a PC pump completion, an additional length of tubing is sometimes run below the tag bar as a tail joint to lower the pump intake. For example, in horizontal wells, the pump may be seated in the vertical section to alleviate wear problems while a tail joint is installed to allow fluid to be drawn from the curved or horizontal sections of the wellbore. This technique can also be used effectively to increase the fluid flow velocity below the pump, which can be important for maintaining solids in suspension. In some cases, tail joints can be used to reduce the gas-to-liquid ratio at the pump intake, although the pressure losses through the tail joint may lead to additional solution gas breakout, resulting in little or no improvement in volumetric pump efficiency.