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 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 This paper discusses the added value of a new approach to exiting an existing wellbore, where the normal practice forces the plug and abandonment (P&A) of the existing lateral before cutting the window into a new lateral, particularly when an off-bottom cemented (OBC) liner is required. The new approach includes the construction of a Technology Advancement of Multilaterals Level 4 (TAML 4) junction to maintain well integrity and the successful development of a re-entry window that allows access to both the existing and the new slim wells. Not only has this technique unlocked massive potential, but it has also led to an enhancement in the utility and reduction in capital expenditure (CAPEX). The successful Level 4 sidetrack and re-entry window deployment is directly related to the robust system design. The application developed includes an anchor with a guide and high-torque capability, a TAML Level 4 junction created in a shape that will lead to smooth, repeatable access in the future, and a customized re-entry window system to further maximize the well potential. The true value is in allowing access to both the existing and the newly drilled lateral without using a rig or decompleting the well. Such operations use tubing exit whipstock (TEW) and pressure isolation sleeves, both of which can be run and retrieved in a rigless manner. The rigless access has allowed the existing lateral to be used as an observation well. Using permanent downhole gauges (PDHGs) enables real-time monitoring of the pressure and temperature and periodic logging to evaluate the reservoir. The newly drilled lateral can be the primary producing lateral; rigless access equally helps recover the well in case of any production challenges. The newly designed multilateral is a game changer for both mature and new developments because it maximizes reservoir production and helps reduce CAPEX by requiring fewer wells to be drilled. The improved well integrity minimizes well workover operations, which creates cost savings. This paper discusses the following aspects:A successful Level 4 junction construction from a slim re-entry existing/mature well. Repeatable accessibility to the lateral and motherbore. Meeting the motherbore objective as required. Delivering an OBC lateral liner and maintaining the well integrity.
Abstract Tubular GRE lining technology has been globally applied used since 1960's in eliminating downhole tubular corrosion, replacing the elevated CAPEX of CRA OCTG and assuring steady oil, gas and water flow through the downhole string with its flow assurance benefits. Compared to conventional carbon steel whose failures are frequent, the GRE lined carbon steel provides long lasting protection which results in huge savings in life cycle cost. Likewise, compared to CRA material capable of withstanding corrosion issues, the GRE lined CS provides direct capital cost savings. Apart from the economic benefits, operators deploying GRE lined CS have enjoyed superior well integrity over the life cycle of the well. Abu Dhabi National Oil Company (ADNOC ONSHORE) implemented this technology in 2013 for the water disposal wells (5 wells as trial, all of them were successful). We will share the results of the caliper logs that have been run into these wells and the inspection of tubing pulled out of the disposal wells after 4 years in service. Following the assessment, which was satisfactory, the first Water Injection well with GRE lined tubing has been RIH in 2021, and plans for Oil producers with GRE lined tubing in Q2-2023. Till the time of writing this paper, 19 GRE lined strings have been RIH in Aon's water disposal wells, and 2 strings have been run in water injection wells (under study and field test and assessment). This paper shares the evolution of this technology within the Aon from the first installation to the development of a contract and how Aon geared to absorb this technology in their system. Some of the challenges that faced the company were: The modifications that were required to the wells’ designs. How the service provider was aware of Aon's operational well intervention jobs. How this is compatible with the lining system.
Yudhia, D. P. (ADNOC OFFSHORE, Abu Dhabi, UAE) | Seyfetdinov, R. (ADNOC OFFSHORE, Abu Dhabi, UAE) | Alhaj, M. (ADNOC OFFSHORE, Abu Dhabi, UAE) | Aziz, M. Abdel (ADNOC OFFSHORE, Abu Dhabi, UAE) | Rabis, P. (ADNOC OFFSHORE, Abu Dhabi, UAE) | Al Ameri, S. M. (ADNOC OFFSHORE, Abu Dhabi, UAE) | AlMarzooqi, A. (ADNOC OFFSHORE, Abu Dhabi, UAE) | Barbera, R. (Dril-Quip, Abu Dhabi, UAE) | Sallam, S. (Dril-Quip, Abu Dhabi, UAE) | Omar, H. (Dril-Quip, Abu Dhabi, UAE)
Abstract Liner hanger operations and well integrity across the liner overlap have been always a challenge in the gas well. Conventional liner hanger relies on elastomeric devices as the primary sealing mechanism to isolate the liner lap strings, with two trips required to deploy the liner hanger, top packer and tie-back seal. This paper will introduce an expandable liner hanger/packer and tie-back system to isolate high pressure reservoir and problematic shale in Offshore Abu Dhabi. The selected single-trip expandable XPak liner hanger/packer and tie-back system offers a metal-to-metal seal throughout the complete liner stack, with 17 to 24 inches of an expandable section on the hanger/packer body that generate sufficient metal-to-metal contact area between the liner and the host casing achieving a robust sealing device that is to be considered as a primary isolating barrier. Feasibility review of technology was then conducted, covering review of running procedure, risk assessment and success criteria (covering HSE, performance, integrity, and efficiency). Business case was issued to install the 13-3/8″ × 9-5/8″ system. The system was deployed in a gas well drilled in 2021. Cementing job of 9 5/8″ liner was conducted smoothly with liner string rotated at 10 rpm while pumping & displace cement. Liner hanger/packer was set with 4,400 psi, hanger setting was then confirmed with 70 klbs overpull and the setting tool was released by slacking off the drill string with 120 klbs. The operation was conducted safely and with zero NPT. The system was successfully demonstrated by the effectiveness of the offered features and its running procedure. Liner and tie-back casing integrity was achieved and confirmed through successful pressure tests. Based on the trial result, the selected single-trip expandable liner hanger/packer and tie-back system achieved the defined success criteria. The actual time saving from deployment of single-trip expandable liner hanger/packer and tie-back system compared to conventional liner hanger in this application is 2.54 rig days. The detailed analysis and operation feedback will be beneficial to assess the suitability of this technology to overcome future drilling and integrity challenges.
Abstract As part of a brainstorming exercise that was conducting, on finding ways to lower well operation and intervention duration and have a better allocation of the Drilling function resources. The idea of using the rigless equipment came into play, prompting a trail in business year 2022. The main objective of this newly developed initiative was to look into opportunities where it could be made use of the light rigless intervention which involves the use of light rigless intervention, which involves the use of specialized equipment and techniques to perform the planned well services rather than the use of a conventional rig or/and heavy equipment. Based on that, an exercise conducted in conjunction with the drilling operation teams was carried out, to review and check the drilling workover schedule for potential wells. The scope of work was defined, cases were studied, and the required resources were prepared. The rigless intervention campaign scope has been completed within planned schedule and budget in addition to these types of light interventions enable use fewer equipment footprint, offer improved safety compared to traditional methods by control risks to workers and use of smaller crew members, and leave a remarkable reduction in carbon emission footprint on each well location which in turn makes a positive differences when it compared with conventional rig-based operations.
Gohar, S. H. (ADNOC Drilling, Abu Dhabi, United Arab Emirates) | Mazrouei, M. Al (ADNOC Drilling, Abu Dhabi, United Arab Emirates) | Kamble, R. (ADNOC Drilling, Abu Dhabi, United Arab Emirates) | Patil, Y. (ADNOC Drilling, Abu Dhabi, United Arab Emirates) | Sas, M. (ADNOC Drilling, Abu Dhabi, United Arab Emirates) | Sinaga, A. (ADNOC Onshore, Abu Dhabi, United Arab Emirates)
Abstract Linerless wells have gained popularity in the United Arab Emirates (UAE) oil and gas industry due to their cost-effectiveness. This type of well architecture eliminates the need for a dedicated 7″ liner run, saving up to 6 days of well time. However, stringent zonal isolation is the most crucial aspect of linerless well construction, requiring the use of meticulous and comprehensive engineering. In this case study, optimized cementing practices were employed for linerless well designs in an onshore oilfield in UAE by utilizing novel cement engineering techniques. The wells in this study were constructed as extended reach drilling (ERD) wells with the 9 5/8″ production casing placed across a carbonate reservoir at an inclination of 90°. Major challenges encountered were overcoming high equivalent circulating densities (ECD) in a single-stage job, requiring cement to surface in absence of mechanical pipe movement. This increased the risk of inducing fractures, channeling, adequate mud removal, and homogeneous cement placement, particularly across highly deviated intervals. To mitigate these risks, a dual-cementing technique was employed in which a newly designed 13.4 PPG light-weight expandable and gas-tight lead cement was used. Additionally, a spacer train was implemented, combining a novel mechanically-scrubbing spacer with large surface area to volume ratio particles for effective cleaning, followed by a biodegradable loss-circulation spacer that provided formation strengthening via a film-forming mechanism. Another challenge was long-term well integrity and cement sheath protection against stress variation during drilling and production phases. To overcome this, multiple mechanical and structural lab tests were conducted including compressive and tensile strength and Young's Modulus measurements. The lab data was incorporated into a stress analysis model to predict the risk of damage associated with the mechanical and thermal loads that the well would encounter. In addition, a 3-D computational fluid dynamics (CFD) model was analyzed to visualize and ascertain mud removal effectiveness and cement placement with emphasis on the highly deviated and lower side of the well. This aided the engineering and optimization of the rheological properties and pump rates of the cement and spacer fluids. The engineered designs and execution parameters resulted in successful cement placement without inducing losses. Post job cement integrity evaluation for the three linerless wells confirmed excellent cement bonding and isolation across the entire section. The results reinforced our cementing practices, meeting integrity requirements. This paper demonstrates the feasibility of employing advanced cementing practices in such types of wells. The engineered techniques and novel designs that were successfully applied to the three trial wells in the field will set the standard for future wells, with the potential to improve the efficiency and cost-effectiveness of linerless wells construction in the region.
Sistrunk, Carrie (Texas A&M University) | Brashear, Andrew Travis (Texas A&M University) | Hill, Dan (Texas A&M University) | Zhu, Ding (Texas A&M University) | Tajima, Tohoko (Texas A&M University)
Abstract When rocks are fractured in tension, the fracture surfaces created are rough, with a wide range of surface morphologies possible. In previous studies of propped fracture conductivity using fractured samples, the fracture surface topography was found to have a strong influence on fracture conductivity and stimulation efficiency. Fracture surface patterns (relatively uniform, randomly rough, step changes, ridges and valleys) strongly affect propped fracture conductivity. Different types of surfaces can result in propped fracture conductivities differing by an order of magnitude or more for identical proppant loading conditions. To generate quantitative correlations including surface topographic effects, consistent samples with well-defined surfaces should be used in the experiments. However, when using actual rock samples to create realistic fracture surfaces by fracturing them in tension, the surfaces created are never the same, even using small samples all taken from the same block. This lack of repeatability in fracture surfaces greatly complicates identification of the effects of the rough surfaces on propped fracture conductivity. To overcome this, we created repeatable rough fracture surfaces using 3D-printing technology. First, we geostatistically generated a numerical depiction of a rough fracture surface. Then the surface was printed with resin using a 3D-printer. The hardened resin model of the rock sample was used to make a mold, which was in turn used to create a rock sample made of cement. High strength cement was used so that the samples had similar mechanical properties to unconventional reservoir rocks. With this methodology, we created multiple samples with identical surface roughness and features, allowing us to isolate and test other parameters, such as proppant size and concentration. Fracture conductivity tests were conducted using a modified API conductivity cell and artificial rock samples that are nominally 7 inches long and 2 inches wide. A well-established protocol to generate propped fracture conductivity as a function of closure stress was employed to test three different proppant concentrations on identical rough surfaces. For all three experiments, 100 mesh sand was used. The study demonstrates how proppant concentration affects propped fracture conductivity behavior in a systematic way.
Abstract Oil and gas wells leakage is a major concern due to the associated risks. Potential issues include habitat fragmentation, soil erosion, groundwater contamination, and greenhouse gas emissions released into the atmosphere. An estimated 2 million abandoned oil and gas wells are believed to be leakage. Proper Plug and Abandonment (P&A) operations are required to ensure these wells are correctly disposed of from their useful operational life. This study aims to build an uncertainty evaluation tool to statistically classify the risk of a well from leaking based on their well information (age, location, depth, completion interval, casings, and cement). Data consists of leakage reports and available well data reports from Alberta Energy Regulator (AER) in Canada. Multiple preprocessing techniques, including balancing the data, encoding, and standardization, were implemented before training. Multiple models that included Naïve Bayes (NB), Support Vector Machine (SVM), Decision Trees (DT), Random Forest (RF), and K-Nearest Neighbors (KNN) were compared to select the best-performing for optimization. RF outperformed the other models and was tuned using hyperparameter optimization and cross-validation. The final model's average accuracy was 77.1% across all folds. Multiple evaluation metrics, including Accuracy, Confusion Matrix, Precision, Recall, and Area Under the ROC Curve (AUC), were used to assess the model and each class against the rest. Feature importance showed an even distribution across the different features used. The model presented in the study aimed to classify wells and label the leakage risk based on the well information associated with its components. This risk evaluation tool could help reduce gas emissions by 28.2% based on the results obtained. This tool can classify the wells to speed the selection process and prioritize wells with higher leakage risk to perform P&A operations and minimize emissions.
Abstract In a rush to install more renewable energy resources, we must carefully consider and mitigate the legacy issues with end of life waster from new solar and wind turbine installations. This paper is about a potential solution for handling legacy assets from wind turbine blades. The paper presents the economic viability to consider well internal capacities as storage sites as well as analyzes the environmental hazards of landfilling the blades. Bisphenol A (BPA) is a chemical used in wind turbine blades. Storage in landfills can put the future health of natural resources and the surrounding areas at risk. BPA can leak out of the dust particles and be hazardous to people and the environment. BPA also degrades in water and sediments under microbial processes. The increased risk of BPA leaching into groundwater resources and the soil from wind turbine blade landfills can damage the food chain and can harm future generations due to exposure to the contaminated resources. The solution discussed here is a potential use of the casing storage of idle wells for housing pulverized blades mixed with Portland cement when the wells are considered for plug and abandonment.
Heimerl, Joseph (Los Alamos National Laboratory) | Ma, Zhiwei (Los Alamos National Laboratory) | Chen, Bailian (Los Alamos National Laboratory) | Mehana, Mohamed (Los Alamos National Laboratory) | Van Wijk, Jolante (Los Alamos National Laboratory)
Abstract Addressing the existential threat posed by climate change requires the widespread adoption of carbon dioxide (CO2) emission-limiting and atmospheric reduction methods. Point source capture of CO2 at power generation and manufacturing facilities, as well as direct air capture from the atmosphere, can reduce atmospheric CO2. After capture, CO2 will need to be stored long-term. One option is the implementation of geologic sequestration (GS) of CO2. Within the United States, oversight authority of CO2 sequestration wells is conducted by the Environmental Protection Agency (EPA), which designates GS wells as "Class VI wells". So far, only a few Class VI wells have been made operational, with a few dozen more in the permitting process. This volume will not be sufficient to meet the need for full-scale CO2 sequestration, and additional wells will need to be delivered in an economic and timely fashion to allow for large-scale CO2 sequestration. A promising option to boost storage capacity would be to retrofit some of the nation's millions of legacy oil and gas wells for use as sequestration wells. We present an analysis of wellbore retrofit, the process of augmenting an old well to meet Class VI requirements, conducted by looking at the EPA regulations, carbon dioxide compatible well design, and a pilot review of some United States wells. This study does not include a review of the geological considerations associated with sequestration but focuses on what will be necessary on a well-by-well basis for successful retrofit. The findings of this analysis illustrate that wellbore retrofits for long-term carbon dioxide sequestration is only suitable for wells that possess the correct combination of well factors and will inject a clean CO2 stream. For ideal candidates, a retrofit would allow for significant time and cost savings compared to a newly- drilled wellbore. The document concludes with considerations for publicly available wellbore data that could facilitate a more robust search for future wellbore retrofits through state databases with the collaboration of operators.