Field Study Examines Wellhead-Penetrator Problems, Solutions in SAGD Operations

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201167, “Wellhead-Penetrator Problems and Best Practices in ESP Thermal SAGD Applications,” by Pat Keough, SPE, Jesus Chacin, SPE, and Kyle Ehman, SPE, ConocoPhillips, prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition–Americas, 10–12 November. The paper has not been peer reviewed. Wellhead penetrators are a critical component in electrical submersible pump (ESP) systems. Harsh steam-assisted gravity-drive (SAGD) conditions impose an even higher level of stress on penetrators. Recently, a sudden increase in wellhead-penetrator failures in the Surmont SAGD ESP operation in Canada led to an enhanced fieldwide root-cause analysis (RCA). The complete paper is a field case study that describes the findings of this RCA and the mitigation measures taken. Introduction Fig. 1 shows a wellhead-penetrator assembly typically used in SAGD operations. This assembly consists of two main parts: a mandrel that seals against the wellhead while carrying power from the surface facilities through the tubing hanger and the lower field-attachable connector that splices the ESP cable and threads into the mandrel below the tubing hanger. Because of the design of the ESP, when an electrical-system failure is detected through traditional means, accurate determination of which electrical component has failed is impossible without first sending a rig, killing the well, removing a portion of the wellhead, disconnecting or cutting the penetrator or cable, and completing further resistance testing on the cable components. At Surmont, 230°C-rated penetrators had proved reliable and electrical failures were almost exclusively caused by a failed downhole component. The produced fluid temperature typically is below 230°C, somewhere between 180 and 220°C during normal operating conditions. However, approximately 12 months after a large installation campaign that almost quadrupled the Surmont ESP population, a sudden increase in penetrator failures was observed. Between late 2017 and early 2019, 18 penetrator failures occurred. These failures accounted for approximately 25% of the ESP-related events in Surmont during this period. These penetrator failures occurred at different runtimes, varying from 148 to almost 900 days, with most occurring 12 to 18 months after being installed. In all instances, penetrator failures occurred at runtimes shorter than the expected ESP mean time to failure (MTTF) of the ESP population. Failure Investigations: Approach, Results, and Recommendations At the end of Q1 2018, the first five failures occurred in succession, which prompted a failure investigation on this group of wells. Nearly all field measurements pointed to a short circuit in the field-attachable connector. Given the special nature of the penetrator design and construction, it was thought necessary to send failed specimens to the manufacturer. Dismantles showed that, in all cases, the high- modulus tape was missing. Without the tape in place, rubbing of leads, development of wear, and an eventual short were all possible when considering excessive thermal expansion. RCA techniques were conducted and identified the potential contributing causes described in this subsection.

Umbilical-Less Tubing Hanger Installation Controls System

The umbilical-less tubing hanger running installation tool, ROCS ("Remote Operated Control System") was first introduced as an R&D project to the market in early 2020. By February 2021, it is in operation for Aker BP in the North Sea on Deepsea Nordkapp. ROCS is specifically designed to increase the robustness and efficiency of running the production tubing in the well. In a traditional operation, the Tubing Hanger Running Tool ("THRT") normally communicates topside through an umbilical. The ROCS eliminate the controls umbilical by having two methods of communication to the THRT, either acoustic or through wired pipe, preference is acoustic. This also eliminates the topside WorkOver Completion System ("WOCS"). The approximately 16meter long ROCS is also designed with a Ready To Run ("R2R") principle, where the ROCS, THRT and Tubing Hanger ("TH") is made ready on land for offshore operations, already connected and tested. The system is redundant and based on a closed loop hydraulics, powered by a subsea HPU, electrically supplied from subsea batteries. The SHPU is small in size and power consumption, capable of providing the required flow at 690bar. The control functions occur through electrically held DCV's ("Directional Control Valve") for controlling all of the required TH functions. The ROCS is capable of performing 3 operations of each TH function within the allocated deployed period. The energy required is provided between the hydraulic accumulators and batteries. Pressure balanced accumulators are included to optimize all deepwater operations. A properly sized clean reservoir is installed, interfacing the pre charged accumulators. ROCS is controlled through a modular and user-friendly topside HMI ("Human Interface Machine"), communicating acoustically or through wired pipe over any type communication protocol. The benefits include removing personnel from red zone, as well as eliminating time to clamp umbilical to the drillpipe. This significantly reduces mobilization of the system to a few hours, which also eliminates the topside deck space considerably. The running time is reduced and allows to increase speed of the drill pipe. This also reduces the risk of damaging production tubing or downhole equipment. There is no risk of downtime due to damaged conduit and the operating weather window is increased.

Novel THOR Technology for Orientation of Vertical XT to Completions

On conventional vertical trees (VXTs) with a tubing hanger (TH) in the wellhead (WH), orientation of the VXT to the TH system is a complicated and expensive process. Leveraging patented technology, the tree to hanger orientation ring (THOR) and tooling were implemented to save CAPEX and OPEX while eliminating risks associated with conventional orientation solutions. An open-water tool installs an external alignment feature onto the wellhead, which is oriented with the tubing hanger already installed in the wellhead. The VXT then orients onto the wellhead with the help of this external alignment feature, resulting in correct orientation with the tubing hanger. This paper discusses the novel technology and its successful development and installation for a subsea project, which revolutionizes the VXT portfolio. Rapid development of THOR technology was required along with expedient project execution. Utilizing digital-twin design techniques such as finite element analysis and operator simulations, the operating life of THOR tooling was investigated in parallel with project engineering. The novel nature of the THOR required unconventional testing, which was performed in-house. Project execution plan was implemented for engineering and manufacturing to successfully build the production equipment on schedule. Comprehensive system integration testing was completed upon the first attempt. The system was deployed to staging facilities before being delivered offshore to the customer and installed subsea in stages during April 2020. Involvement of the operators and installation contractors during the development stage made THOR's first deployment attempt a major success with zero recorded nonproductive time, even during COVID-19. THOR technology reduces the number of components as well as the weight and size of the equipment. The novel THOR equipment can be run by a light intervention vessel rather than conventional equipment, which requires mobile offshore drilling units. The time spent to deploy the VXT system is also reduced, minimizing indirect supply-chain and field-service-related carbon emissions. This further enables reduced carbon emissions and overall carbon footprint of the entire project. The field-proven THOR technology is an evolutionary orientation technology that simplifies the installation operations for the vertical tree and tubing hanger. This technology maintains the robust conventional system configuration post installation and hence does not affect reliability of the VXT system.

NUMERICAL AND ANALYTICAL MODELING OF STRESS-DEFORMED STATE OF THE METAL RING SEAL OF THE TUBING HAGER

The article presents a numerical and analytical modeling of the stress-strain state of a metal ring seal of a tubing hanger under installation loads, as well as under the influence of well pressure. An analytical method for calculating strength and tightness within the elastic formulation is proposed. The calculation by the finite element method was carried out in order to take into account plastic deformations, which make it possible to study the influence of the geometry of the contact zone of the sealing ring on the width of the contact pad and the magnitude of the contact pressure. Comparison of the calculation results by the analytical method and the finite element method is carried out. It is shown that the analytical method, as less labor-intensive, can be used at the initial stages of designing this type of equipment.

Wellhead Design Enables Offline Cementing and a Shift in Operational Efficiency

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202439, “Pushing Malaysia’s Drilling Industry Into a New Frontier: How a Distinctive Wellhead Design Enabled Implementation of a Fully Offline Well Cementing Resulting in a Significant Shift in Operational Efficiency,” by Fauzi Abbas and Azrynizam M. Nor, Vestigo, and Daryl Chang, Cameron, a Schlumberger Company, prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Traditionally, rigs are positioned over a well from the moment the surface casing is drilled until the installation of the wellhead tree. This results in the loss of precious time as the rig idles during online cementing. However, in mature Field A offshore Terengganu, Malaysia, a new approach eliminated such inefficiency dramatically. Operational Planning With oil production in Field A initiated in October 2015, historical data on well lithology, formation pressure, and potential issues during drilling were available and were studied to ensure that wells would not experience lost circulation. This preplanning is crucial to ensure that the offline cementing activity meets the operator’s barrier requirements. Petronas Procedures and Guidelines for Upstream Activities (PPGUA 4.0) was used for the development of five subject wells in Field A. In this standard, two well barriers are required during all well activities, including for suspended wells, to prevent uncontrolled outflow from the well to the external environment. For Field A, two barrier types, mechanical and fluid, allowed by PPGUA 4.0 were selected to complement the field’s geological conditions. As defined in PPGUA 4.0, the fluid barrier is the hydrostatic column pressure, which exceeds the flow zone pore pressure, while the mechanical barrier is an element that achieves sealing in the wellbore, such as plugs. The fluid barrier was used because the wells in Field A were not known to have circulation losses. For the development of Field A, the selected rig featured a light-duty crane to assist with equipment spotting on the platform. Once barriers and rig selection are finalized, planning out the drill sequence for rig skidding is imperative. Space required by drillers, cementers, and equipment are among the considerations that affect rig-skid sequence, as well as the necessity of increased manpower. Offline Cementing Equipment and Application In Field A, the casing program was 9⅝×7×3½ in. with a slimhole well design. The wellhead used was a monobore wellhead system with quick connectors. The standard 11-in. nominal wellhead design was used for the wells with no modifications required. All three sections of the casing program were offline cemented. They were the 9⅝-in. surface casing, 7-in. production casing, and 3½-in. tubing. The 9⅝-in. surface casing is threaded to the wellhead housing and was run and landed with the last casing joint. Subsequent wellhead 7-in. casing hangers and a 3½-in. tubing hanger then were run and landed into the compact housing.

STRENGTH ANALYSIS OF THE SPLIT RING OF THE TUBING HANGER LOCKDOWN MECHANISM

The article discusses the analysis of the stress-strain state of the split ring of the locking mechanism of the pump and compressor pipe suspension in the unpressed position by analytical and numerical methods. In the analysis by numerical method, the rationale for using an elastic-plastic model of the material is given and the structural strength is estimated.