The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Abstract Self-healing wellbore sealants, that (chemically) react with leaking fluids such that when leakage pathways form, they are sealed rather than widened, can be a key technology for ensuring long-term seal integrity in CCS and other geological storage applications. Developing such sealants requires representative and reproducible testing methods, to assess how a leakage pathway through a selected sealant material evolves when exposed to a flow of leaking fluid under in-situ conditions. Here, we will present novel experiments, in which a reproducible simulated leakage pathway through a sealant sample is exposed to a constant flow of supercritical CO2. During exposure, up- and downstream fluid pressures are monitored to assess changes in permeability. Microstructural and mineralogical changes are assessed afterwards, using SEM with EDS.
Todorovic, Jelena (SINTEF Industry) | Stroisz, Anna Magdalena (SINTEF Industry) | Duda, Marcin Ireneusz (SINTEF Industry) | Agofack, Nicolaine (SINTEF Industry) | Lange, Torstein (SINTEF Industry) | Nilsen, Nils-Inge (SINTEF Industry) | Aas, Per Gunnar (Disruptive Value Group) | Sefidroodi, Hamidreza (CannSeal, previously/ Interwell, presently) | Ringe, Thomas (CannSeal, previously/ Interwell, presently)
Abstract Development of wellbore sealant alternatives to cements is a topic of high relevance for production and injection wells, permanent plugging and abandonment, and remediation of leakage behind the casing. Some examples of alternative sealants are epoxy-based sealants, geopolymers, and bismuth-based alloys. Depending on the application, sealing materials are expected to encounter challenging downhole conditions, such as corrosive environments (e.g., CO2, H2S) and pressure or thermal cycling. This is especially significant for permanent plugs, where long-term perspective needs to be considered. In this work, we conducted long-term exposure of three polymer-based wellbore sealants (labelled as A, B and C) to an artificial seawater water environment with dissolved H2S gas. The polymer-based sealants are compared to each other and to a Portland G cement blend that was subjected to the same testing procedure. The experiments reported here are a part of a more extensive campaign that aims to study the behaviour of these materials after up to 12 months exposure to H2S. The aging tests were performed as batch-exposure conditions in a pressure cell at 100 °C and 10 bar. Cylindrical (core) samples of the same material were submerged together in artificial seawater in a glass beaker, and a mixture of H2S and nitrogen was dispersed into the seawater. We characterized mechanical properties before and after H2S exposure by unconfined compressive strength (UCS) tests. X-ray micro-computed tomography (CT) was performed to visualize changes potentially induced by the reaction with H2S. After H2S exposure, sealants A and B displayed significant axial and radial deformation during UCS tests (ductile behaviour), which is a very different behaviour compared to a typical wellbore cement. Sealant C exhibited ductile behaviour during compression but without considerable deformation. For comparison, strain at the peak stress was in the order of 200-300 mm/m for sealants A and B, whereas for C it was approximately 60 mm/m, after one month of H2S aging. For all three materials, a decrease of UCS and Young's modulus was observed after H2S exposure. For sealant C, the UCS was still relatively high after three months of aging, at around 70 MPa, which was about 50 % decrease from the reference value. CT results revealed no obvious progression of a reaction front for sealants A, B and C, however, different effects (e.g. change of porosity, precipitation, cracking) were observed throughout the volumes. The unique behaviour of these materials under stress and the possibility of tuning the physical and chemical properties hold vast potential for different applications. One of the long-term goals is to optimize the material properties to make them more suitable for the permanent plugging of both petroleum and CO2 wells.
Abstract This work presents experimental studies on a new tool concept to address casing-casing-annulus (CCA) pressure leak challenges in the drilling industry. The new method uses an intervention-type tool that allows for exiting the casing, cleaning cement behind, and injecting any required sealant to block fluid migration on the annular side. Addressing such CCA challenges is essential for increasing the production time and maintaining wellbore pressure integrity. A combination of 3D modeling and experimental studies is used to evaluate the feasibility of the new concept for addressing CCA fluid migration challenges. This study focuses on the development and evaluation of a tool that allows accessing and sufficiently cleaning cement in multiple CCAs. We have successfully tested a scaled tool. This tool can punch a small hole in a casing at a unique angle and clean cement behind it by drilling spirals on the annular side. The new method for accessing the annular side of the casing and cleaning cement behind it has been developed and successfully tested using scaled model rigs. Studies have involved an early proof of the concept in plastic and steel. We have also simulated cement with fluid communication channels behind the casing with a successful attempt of removing it. The experimental test results are being used to further develop a robust, downhole field-deployable tool and method that captures the essential features required to access and operate in CCA areas. The current study suggests that a significant section of cement can be removed by the proposed method: One small-diameter hole is drilled in the casing, and then a cement removing assembly is run in a spiral motion on the annular side of this casing. A suitable sealant can be injected in the created void in cement to stop potential fluid migration. This experimental study suggests that the CCA can be accessed and resealed with a minimum time and equipment if required. This CCA milling-injection system (patent pending) utilizes a novel, easily-deployable tool. This tool enables milling access into the annular side of designated casings, and enables cleaning the cement behind it. The new system only mills one hole in the casing limiting its damage and providing the ability to clean a significant section of the cement at the desired depth. This helps address potential CCA leaks, saves time and cost.
Abstract Production from a subsea well was halted due to hurricane activity in the Gulf of Mexico. When the well was returned to production, the annulus experienced a loss of pressure integrity. To achieve regulatory compliance and return the well to production, annular integrity had to be restored in a safe, expeditious manner. This paper will describe the process of operations undertaken to cure this well integrity issue utilizing pressure activated sealant deployed via coiled tubing. Pressure activated sealants have been utilized for a number of years to efficiently cure leaks in a wide variety of applications. One of the first challenges to be addressed when considering a sealant repair is the method of getting the material to the leak site. For the purpose of the subsea well in question, coiled tubing was used to convey the sealant to the sea floor from a service vessel. An ROV then connected the coil to an external tree cap via a flying lead after which the sealant was introduced to the annulus by lube and bleed pressure cycles. The annular integrity issue was analyzed in an effort to determine leak severity and location. Pressure trends noted at annular pressures of 4000 psi indicated a leak ranging from 0.15 – 1.5 lit/min. Gradient analysis indicated that the leak was deep in the completion potentially at a liner lap or the packer. Based on this information a sealant blend approximately 2 ppg heavier than the completion fluid was developed for the purpose of curing the leak. An external tree cap was installed on the well in order to provide access to the annulus of the well via a hot stab connection. About eleven cubic meters of sealant was transferred to the annulus through 2" coiled tubing extended to the sea floor connected to the well via a flying lead. A series of lubricate and bleed cycles were performed to accomplish this without exceeding predetermined pressure limits. After allowing the sealant to settle on the packer, annular pressure was maintained to allow the sealant to cure at the leak site. The pressure differential at the leak caused the liquid sealant to form an elastomeric seal. A positive pressure test was obtained shortly after the process and the well was returned to production. An example of how using pressure activated sealants designed to polymerize only at a leak site affords options to expensive workovers on subsea wells will be provided herein. The use of this technology in concert with coiled tubing deployment represents an expeditious, economic approach to solving complex well integrity issues.
Abstract The bonding properties between a sealant and steel casing are an important component of well barrier. However, there is no consent about how sealing materials should be tested and qualified, and the understandings around the bonding interface and its mechanisms of failure remains uncertain. A custom setup and a systematic interface analysis procedure was established to test the hydraulic bond sealing properties of different sealants, and to investigate their interface with a L80-Cr13 steel casing. The results of hydraulic bond sealability was correlated with macro and microstructural evidence of the bonding interface to understand the behavior and the performance of class G cement and a geopolymer recipes. The geopolymer recipe showed improved sealing performance in relation to class G cement. The interface analysis suggests that, in addition to the mechanical interlocking mechanism, the geopolymer sealant has a strong bond with the coating of the steel casing, as a secondary adhesion mechanism. Understanding the interface and the mechanisms of failure may be the key to further develop current and future sealants, and to reduce risk of leak and to reduce cost with well intervention in P&A operations.
Abstract The subject well was a subsea producer in the Gulf of Mexico exhibiting pressure loss from its production annulus. An approximately 40 mL/minute (15 psi/hour) leak was identified via logging techniques during a riser-based intervention campaign. This leak was then determined to be past the production packer element set. The well was isolated and the data was reviewed to identify forward options. Though considered, a riser-based intervention was eliminated as an option to restore integrity and return it to production due to technical, scheduling, and economic considerations. Based on these constraints, the operator opted for a sealant remediation approach. The operator considered multiple sealant products, ultimately working with an engineered sealing solution provider to analyze all available data to evaluate leak characteristics while still progressing other contingencies. From these parameters, a subsea sealant blend tailored to the application was prepared and successfully tested to confirm its suitability for this application. A remediation procedure was then developed to fill subsea bladders with sealant, which were then spotted on the sea floor to inject the sealant into the annulus through a Well Stimulation Tool, Bass Adapter, and Tree Running Tool utilizing an engineered lubricate and bleed volumetric injection technique. Because the annulus was fluid packed, a series of four lube and bleed cycles were performed to compress annular fluid with sealant and bleed back completion fluid to a host platform via the flowline. The selected blend of sealant was approximately 240 kg/m heavier than the packer fluid to facilitate its fall and allow for fluid swap in between cycles. This ensured only annular fluid was being bled off, rather than the injected sealant. After the final cycle, annular pressure was maintained at the maximum threshold for a cure period before testing the repair. Within one day following the final lube and bleed cycle, the sealant had successfully accumulated on top of the packer as designed. The applied pressure maintained during the cure period had activated the sealant and the annular pressure remained steady over the operator's monitoring period. Given these positive indications, the operator tested the repair with no pressure loss over the test interval. All internal and regulatory requirements had been satisfied, allowing the well to be returned to production. This sealant was designed to polymerize at the packer elements, which provided the needed pressure differential. This differential triggered a chemical reaction, thereby creating a flexible, solid seal only at the leak site. This newly formed and tested seal was designed to furnish a seal for the forecasted production profile and excess sealant would remain liquid above the packer. In the event that the leak was to return, the operator would have the capability to perform an annular pressure manipulation sequence from the host platform to activate residual sealant, thus re-establishing integrity.
Abstract The traditional solution for capping abandoned oil and gas wells is to fill portions of the open well with cement. However, cement is not ideal for plugging or capping because it often results in an ineffective seal. Cement proves ineffective due to shrinkage, inability to bond to steel casing, degradation over time, and a large carbon footprint in production. To be a solution for greenhouse gas (GHG) emissions from abandoned wellbores, plugging must be effective indefinitely. Moreover, the effectiveness must be documented over time. Thus, the conventional approach of plugging with cement and walking away offers no documented proof of GHG emission mitigation. In this work we suggest the use of a proprietary polymer-based sealant for plugging and abandonment. The sealant, referred to TSN-20, has superior flowability, excellent bond strength to steel and rock, is very ductile, and is thermally stable. TSN-20 sealant can penetrate, flow into and seal extremely thin microcracks (< 30 microns) where cement and most other sealants cannot flow. These small microcracks are problematic leakage pathways for methane and other GHGs. Further, unlike cement, TSN-20 bonds to steel and rock, is very ductile, thermally stable, and resist harsh downhole conditions, including acids and hydrocarbons. Tests showed TSN-20 can dramatically reduce the flow rate after one sealant injection. TSN-20 sealant can be used to mitigate methane gas emissions in abandoned oil and gas wells.
Howley, Grace (Chevron) | Winegarden, Jason (NexTier Oilfield Solutions) | Petrie, Paul (NexTier Oilfield Solutions) | Michel, Cody (NexTier Oilfield Solutions) | Algadi, Otman (NexTier Oilfield Solutions) | Drevdal, Kjell Erik (Flopetrol Well Barrier AS) | Rygg, Vidar (Flopetrol Well Barrier AS)
Abstract When a well is shut in for an extended period, the mechanical integrity of the production casing must be verified periodically to ensure there are no leaks in the casing that could lead to potential fluid migration between the producing zone and other formations along the wellbore. Traditionally, these mechanical integrity tests involve moving in a workover rig, tripping production tubing out of the well, setting a mechanical bridge plug above the highest set of perforations, and then pressure testing the casing. This operation is very time- and labor-intensive, with significant safety exposure risks for personnel involved. This paper describes work performed on 83 wells in the DJ Basin where an alternative method, not requiring a workover rig, was used. In this case, conventional cementing equipment was used to pump a Bingham-plastic nonconsolidating sealing material with a high-solid-volume fraction through the tubing to the perforations. This sealing material is a high-quality, quartz-based slurry using an engineered particle-size distribution (PSD) from <100 nm to 2 mm. The specific PSD of the solids in this slurry is designed to maintain pumpability and ensure near-zero permeability once the slurry is in place. The sealing material creates an impermeable barrier across the perforations, which enables the casing to be pressure tested. The operational simplicity of this material offers improvements to both operational efficiency and safety risks. This slurry also poses little to no risk to the environment from an accidental spill or exposure, as it is a purely natural, silica-based product. The silica-based slurry performed successfully, and the resulting mechanical integrity tests were equally successful. This paper explains the state regulations surrounding the mechanical integrity test, a comparison of the advantages seen with the alternative method, a detailed description of the job execution, and a summary of results observed in the cases where this alternate method was used.
Abstract An openhole gravelpack (OHGP) gas well was planned as part of an infill drilling campaign on a mature Norwegian Continental Shelf field. A geological pilot hole unexpectedly identified a significant pressure differential between two reservoir intervals. This paper describes an innovative modification of the lower completion, within a short turnaround time, in order to manage the clean-up of the reservoir intervals and limit crossflow. Calculations based on the pilot hole results predicted that the low pressure reservoir would not flow until there was significant depletion in the high pressure reservoir. This risked formation damage due to delayed clean-up. Additionally, there was potential for very high crossflow rates that risked mechanical damage to lower completion equipment and/or causing formation damage. There was insufficient time to completely redesign the completion. A solution, supported by simulations, showed that a fixed choke in the lower completion would enable immediate clean-up of both reservoir intervals. Additionally, aplug had to be set in the gravel-filled annulus to prevent flow diverting around the fixed choke. These modifications would reduce the potential crossflow rate to an acceptable level. The OHGP was performed as originally planned. A wireline tool was run to inject an epoxy resin plug into the gravel and the fixed choke was then set at the same depth. The well was cleaned up as planned to the drilling rig, with both reservoir intervals observed to be producing. The choke toolstring included an additional flow area that automatically opened after a pre-defined time delay. Simulations predicted the pressure differential at this time to be significantly lower. Reducing the choking effect in this way, once the risks from crossflow at the start of well life had been minimised, avoided hindering production in later well life. The well has performed as expected with no indications of production impairment having occurred, despite the initial period of high differential pressure between the reservoir intervals. This is believed to be the first injection of epoxy resin into a newly completed gravelpack. Coupled with the implementation of the two-sized choke it has been possible to manage a problematic reservoir pressure differential in a new well without resorting to costly and lengthy redesign of the completion.
Daohmareeyor, Tuanangkoon (Halliburton) | Nguyen, Tran Thang (Halliburton) | Wattanasuwankorn, Reawat (Halliburton)
Abstract Unwanted water production in mature wells is one of the main issues for oil and gas operators worldwide, causing several economic issues related to hydrocarbon production. Furthermore, in this scenario, the swell packer installed between the water and oil-producing intervals had failed, resulting in communication behind the casing. This created difficulties when trying to shut off water-producing intervals without impacting the oil-producing intervals. This paper will discuss and outline the shut-off technique, factors considered as part of the job design, the sealant and temporary gel protection design with lab testing, and describe the job implementation of this case study. Hydroxyethyl Cellulose (HEC) based gel was selected as the temporary zonal protection in the lower, low-pressure reservoir interval, while the sealant gel was designed to shut off the higher pressure upper reservoir interval. The use of Coiled Tubing (CT) allowed the fluids to be placed precisely at the desired interval before applying squeeze pressure to force the treatment fluid further into the near-wellbore region, increasing the overall chance of success. Several critical concerns were outlined, such as the inability of the HEC based gel to be able to set and self-degrade in the required time, excessive gel penetration into the formation leading to formation damage, difficulties for wellbore clean up after the treatment, and the uncertainty of the leaking swell packers capability of sealing between the intervals behind the casing. Multiple lab tests were also designed to verify the suitability of the temporary gel and thixotropic particulate gel systems in achieving overall operational success. The zonal protection fluid treatment was successfully mixed and pumped according to plan to create the temporary zonal protection (barrier). Verification was achieved by tagging the top of the barrier and observing the pressure change in the real-time downhole gauge. The thixotropic particulate gel sealant treatment was then tailed in and squeezed into the upper interval to shut off the zone and create an annular barrier behind the casing to isolate different intervals. Once the fluid treatment stage was complete, all the remaining gel in the tubing was successfully removed using CT with a rotating jet nozzle. An organic acid blend was then squeezed across the lower intervals to accelerate gel degradation time, followed by the flow back operation to test the treatment effectiveness. Final flow test results showed a reduction in water cut from 82% to 64% and an oil production increase of 400 bopd to 550 bopd. A significant challenge was to create the temporary zonal protection of the lower oil-producing intervals and shut off the water-producing interval above while creating an annular barrier behind the casing within the same well. This achievement of a successful operation with detailed fluid design, placement techniques, risk mitigation plans, and good collaboration between the service company and operator can serve as a recommendation for wells with similar issues while providing an alternate cost-effective solution to extend the life of the well without the need to abandon intervals or re-complete existing wells.