Technology Focus: Offshore Drilling and Completion (October 2025)

The world's first Arctic subsea producing gas well was successfully completed and produced to shore by means of a wet Christmas tree in April 1978. This paper describes the unique design of a combination land and offshore drilling rig and air transportable subsea blowout preventer for drilling and completing subsea wells from a floating ice platform. The drilling and completion of Panarctic Drake F-76 is described. The design of a prototype subsea wet tree and diverless flowline connector is also discussed. The well was drilled and completed as a demonstration well in 181 feet of water, 3,050 feet from shore using a rig supported by a floating ice platform. The operation demonstrated techniques which could be used to develop extensive gas reserves in water depths to 1,500 feet located up to 15 miles offshore in the Canadian Arctic Islands. INTRODUCTION In 1973 Panarctic Oils Ltd. developed a system of drilling exploratory gas wells offshore between the Canadian Arctic Islands. Exploration had been taking place onshore since 1961 and it became evident that the six gas fields which were discovered onshore all extended offshore, under ice covered waters. As conventional offshore drilling techniques could not be used in the area, a drilling method was developed wherein the ocean ice was flooded and thickened, developing sufficient strength to support a land type of drilling rig, modified for offshore drilling. The major area of current drilling activity is centered at about 760N latitude and l080W longitude. Fig. 1. The area covers a 450,000 square mile sedimentary basin of which about 70% is covered by ice year round. Reserves totalling approximately 13 trillion cubic feet of sweet natural gas have been found and eventually will be connected to markets via a proposed 2,300 mile Polar Gas Pipeline. Starting in 1974 and until the end of the 1979 drilling season a total of 13 offshore wells have been drilled using offshore drilling systems adapted to land rigs supported from floating ice platforms. These systems have been effective in drilling in water depths up to 1,200 feet at locations up to 20 miles offshore at costs comparable to land drilled wells. In 1976 planning commenced to develop a system for drilling and completing an Arctic offshore gas well. This project involved the design and construction of a new and larger ice supported rig, a larger and more conventional subsea BOP stack, a subsea tree and flowline connector, flowlines and control lines to shore and shore based test facilities. DRILLING AND COMPLETION SYSTEMS A study was conducted in 1976 by Tri Ocean Engineering of Calgary to determine the most suitable means of drilling, completing and testing an offshore well to demonstrate and test technology that eventually could be used to develop the reserves commercially.

And now, what? We have been experiencing high oil prices for several months, which quickly translated into high rig rates. Of course, rig market is one obvious direct consequence of the current economic context, but this might not be the only one. During the past months, we have seen operators drilling deeper to look for (and find) reservoirs in places where geologists did not see reservoirs 10 years ago because of limitations of seismic technology or of geological concepts. These wells cost tens of millions of dollars, and even if the learning curve improves, they will remain expensive. This trend has started in the Gulf of Mexico, but this simple idea of drilling deeper could soon apply in the North Sea, west Africa, Middle East, or Far East—in fact, probably all over the world. The established energy-demand growth also has the oil industry focusing on maximizing recovery from each reservoir. Of course, people may try enhanced oil recovery in the end to recover the residual oil, but the first answer is to drill for reservoirs that were bypassed or which previously were too small to be economical. In this respect, minimizing well costs will still remain a major objective. In the meantime, and even if costs increase, use of complex completions may increase: sound monitoring and remotely controlled multizone completions will be implemented more often to optimize reservoir management. Once again, technology will allow us to face these new challenges. But this technology will not be enough if new generations of drilling and completion engineers are not attracted by our profession and well trained. This issue may be at least as challenging as the technical one. In both areas, SPE has a role to play, and it will. Offshore Drilling and Completion additional reading available at the SPE eLibrary: www.spe.org SPE 96154 "10K Dual-Splitter Wellheads: 1st Worldwide Application on the Development of an Offshore Gas Field," by J.B. Faget, Total E&P, et al. SPE 99135 "Integrating Emerging Drilling Methods From Floating Drilling Rigs—Enabling Drilling Solutions for the Future" by J.R. Kozicz, Transocean, et al. SPE 93866 "Deepwater Subsea Well Intervention—The Future Solution" by A.J. Dick, Expro Group Available at the OTC Library: www.otcnet.org OTC 17279 "Drilling Observations of Possible Hydrate-Related Annular Flow in the Deepwater Gulf of Mexico and Implications on Well Planning," by S.C. Williamson, BHP Billiton Petroleum Inc., et al.

This paper discusses the experience and lessons learned during three years of electrical submersible pump (ESP) operation in heavy and viscous oil in the Peregrino field. Artificial lift applications on heavy oil fields have been a challenge for operators, and the Peregrino field is a good example for this type of ESP application. An ESP was designed to enable a wide operation window to fulfill reservoir conditions changes and to focus on the extended run life and overall lifting efficiency. Three different ESP configurations were applied to produce liquid rates from 1500 to 20000 STB/d utilizing 1100-HP and 540-HP motors. Upper completions using a packer and capsule solution were selected to comply with all production conditions. Peregrino field is a Statoil asset located in Campos Basin, approximately 85 km offshore from Cabo Frio/Rio de Janeiro state in Brazil. The oil in Peregrino has viscosity between 129 cp to 364 cp, and the API gravity varies between 13° and 15° API. The first phase of field development comprised two drilling-capable wellhead platforms and a centrally moored FPSO. Currently, there are 27 producer wells, including 3 multilaterals and 6 injectors in operation. The field is currently producing close to 100,000 STB/d of oil and has achieved a production record of 104,292 STB/d in July 2013. The learning and experience developed from the ESP design phase through three years of operation represents a very important set of best practices. This information can be used by the industry as a complete field-proven method of ESP project implementation, particularly when dealing with high flow rates, high horsepower, and viscous oil ESP operations in an offshore environment.

With the rapid development of computer, computer vision technology is also making rapid progress. In this paper, deep neural network algorithm is used to improve the technology of computer vision, improve the visual effect, and at the same time, innovative algorithm structure, improve the identification of pattern recognition. Computer vision and pattern recognition is a very cutting edge technology that has given people very advanced tools for vision and recognition. At present, the technology can control more accurate image resolution and improve the ability of pattern recognition. This article mainly explains the process of using deep neural network algorithm to improve computer vision and pattern recognition from the internal mechanism, and reveals the working principle and internal mechanism of computer vision and pattern recognition technology application. Data analysis proves that the pattern recognition application established by deep neural network algorithm performs very well in the field of vision and pattern recognition.KeywordsDeep neural network algorithmComputer visionPattern recognitionTechnical application

Handling drilling and production waste associated with oily contaminated drill cuttings, NORM and produced water is an environmental and economic issue in offshore drilling and production operations. There are a number of waste management options and subsea injection into suitable geological formations can be a preferred one. This is because it can achieve zero discharge operations; eliminating transportation and spill risks. It can also be economically favorable. Although subsea drill cuttings and produced water re-injection operations have been conducted in an environmentally acceptable manner, system design and operational experience are limited. A few worldwide drill cuttings re-injection operations from mobile offshore drilling units are reviewed first in the paper. Lessons learned from these and other system design and operational experience include a detailed subsurface study and careful engineering, wellhead and injection system design and effective communication to handle emergency disconnect, quality control on well integrity and slurry injection procedure. Challenges and best practice guidelines for waste injection operations from subsea wellheads are given to minimize failure and maximize success. Introduction Growing environmental regulations and constraints put pressure on drilling operations to find environmentally friendly and economically sound solutions for handling drilling waste. Drill cuttings re-injection (DCRI) operations into suitable geological formations have been successfully implemented all over the world.1–13 Figure 1 shows a schematic of DCRI process. Briefly, the drill cuttings from shale shaker are milled to small particles (300 microns or less), in the presence of water, usually seawater or other wastewater. The resulting waste slurry is pumped into sub-surface fractures created by injecting the slurry under high pressure into the disposal formation. Depending on drill cuttings generation rate, the waste slurry is injected either continuously or intermittently in batches. A continuous slurry injection scheme is expected to lead to an extended disposal fracture, while periodic re-injections would promote the development of multiple fractures and thus a compact domain of smaller multiple fractures from the wellbore. The batch process consists of intermittent injections of roughly the same volumes of slurry and shutting-in the well after each injection. This allows the disposal fracture to close onto the cuttings and to dissipate any build-up of pressure in the disposal formation. This may be impractical when re-injecting into low leak-off shale as the target disposal horizon when drilling rates and thus the slurry generation rates are relatively high. In practice, therefore, re-injections may shift from essentially continuous mode during drilling of large hole sections to periodic as the cuttings generation rate declines with the well approaching TD. Although drill cuttings re-injection has been applied since early 1980s, these operations have mostly been restricted to fixed platforms; annular re-injection into subsea wells, where drilling operations were in progress, had not been feasible until early 1993. BP, through a Drilling Engineering Association (DEA) JIP, conducted the first field trial DCRI operation in March 1993 into the annulus of a subsea well from a mobile offshore drilling module unit (MODU).14, 15

Recent developments in computer vision (CV) technology have significantly improved the management of beef cattle feeding systems by enabling precise monitoring and adjustment of feed intake based on individual needs. This study introduces an automated approach for identifying cattle at feeding bunks using CV and evaluates the effectiveness of a feeding bunk scoring system to optimize cattle feeding strategies. Utilizing a high-definition video capture setup, our research focused on the feeding behaviors of 6 heifers in one pen with the Calan Feeding System (American Calan, Northwood, NH). We deployed three Reolink PoE cameras (Model D400) strategically positioned above the feeding bunks, each overseeing two feeding bunks, to monitor feeding activity comprehensively. The cameras were set to record in Full HD (1920 x 1080 pixels) at 30 frames per second. We processed the frames using Python’s OpenCV, resulting in 600 images that composed an array with dimensions 600 x 400x450 (pixels) x 3 (RGB). These images served as the basis for our analysis, which involved feature extraction via a ResNet-50 convolutional neural network, followed by dimensionality reduction through Principal Component Analysis (PCA) and t-distributed Stochastic Neighbor Embedding (t-SNE). Our methodology included the use of k-means clustering to detect the presence of cattle at the bunk, achieving an Adjusted Rand Index (ARI) of 0.9933. We applied the DBSCAN clustering algorithm in the ‘cattle present’ images for individual animal identification, obtaining an ARI of 0.9174, indicating high model accuracy. To assess feeding efficiency, we analyzed 12,156 images of feeding bunks obtained using the same Python’s OpenCV approach and then classified them into six categories based on Lundy et al., 2015: S00 (no feed), S05 (scattered feed), S10 (thin layer), S20 (25 to 50%), S30 (>50%), and S40 (untouched). Using a training, validation, and testing split of 70%, 15%, and 15%, respectively, our model demonstrated exceptional precision, recall, and F1 scores of 0.9989 and predictions in the Confusion Matrix testing accuracy of 99.89%, showcasing the model accuracy. However, when applied to a similar classification using the same Calan gate system, with 7,905 images, the performance of the model decreased, with less precision (0.5868), recall (0.3982), and F1 score (0.3653), most related to classes S10, S20, and S40, underscoring the need for further model refinement. Our findings highlight the potential of integrating CV into precision livestock farming, automating the identification of cattle at feeding bunks, and correlating it with feeding scores to estimate individual consumption accurately. This integration promises to enhance sustainable farming by enabling more precise resource utilization and optimizing individual animal performance. With CV technology, producers can significantly improve production efficiency, health management, and environmental sustainability within their operations. The technology also has a crucial role in reducing operational costs, making it a cost-effective and sustainable production method.

Deepwater areas offshore the Gulf of Mexico, Angola, and Brazil contain vast oil and gas deposits that underlie thick salt formations. Drilling wells to recover these resources can be challenging because of extreme water and reservoir depths, adverse environmental conditions, and complex tectonics. In particular, stress changes can occur in the vicinity of salt diapirs that are of sufficient magnitude to affect fracture gradient and wellbore stability, and the vast majority of difficult drilling events associated with salt diapirs in the deepwater Gulf of Mexico are in fact associated with the salt – sediment interface. In prior work, non-linear finite element analyes were used to identify the style and magnitude of near-salt stress changes for several idealized diapir geometries. While providing insights, the analyses for idealized diapir geometries remain essentially unvalidated. The work reported here is intended to provide key validation for the conceptual model and numerical methodology developed to predict near-salt stress changes. In 2002, Conoco drilled the Spa prospect, Walker Ridge 285 #1, in the Gulf of Mexico to a depth of 29,452 feet MD / 29434 feet TVD, penetrating a nearly ten thousand foot salt section. While the potential for reduced fracture gradient below salt was recognized in well planning, pre-drill pore pressure and fracture gradient estimates were nevertheless based on seismic velocities in the adjacent abyssal basin. The sub-salt section was difficult to drill, and several formation integrity tests were performed. We developed basin-scale finite element models to represent the geometry of the salt diapir and performed non-linear geomechanical simulations to predict the stress changes in and around the diapir. The simulations predict stress perturbations that vary spatially in accord with the complex and irregular salt geometry. Significant perturbations are predicted adjacent to the salt diapir, and the models predict the reduction in fracture gradient observed sub-salt (nearly 3 ppg). This work thus serves to validate non-linear finite element stress analysis techniques that can be applied to reduce risks when drilling through massive salt diapirs. Besides providing a geomechanical basis for understanding sub-salt fracture gradient reductions, this work also demonstrates the potential for significant stress distortions associated with topography along the top of salt.

Untreated oil-based drill cuttings from offshore drilling operations pose a severe threat to marine ecosystems, potentially disrupting aquatic life and water quality. Washing separation technology provides an effective method for treating these cuttings. However, conventional stirred tank reactors, commonly used for offshore washing, face significant limitations, including their large spatial footprint, high energy consumption, and lack of operational continuity, which hinder their practicality in offshore environments. As a result, pulse scrubbers have emerged as a highly efficient alternative, offering improved performance and adaptability for treating oil-based drill cuttings. This study introduces a dense discrete phase model to analyze the liquid-solid flow characteristics within pulse scrubbers. The results demonstrate remarkable enhancements in operational metrics: the average turbulent kinetic energy surges sevenfold, significantly improving mixing efficiency; particle retention time extends by 65.8%, allowing for more thorough treatment; and the maximum liquid-solid relative velocity difference reaches 0.14 m/s, indicating enhanced separation dynamics. These findings highlight the potential of pulse scrubbers as a technology for sustainable offshore drilling waste management.

Enablers to computer vision technology for sustainable E-waste management

The unsafe behavior of construction workers is one of the main causes of safety accidents at construction sites. To reduce the incidence of construction accidents and improve the safety performance of construction projects, there is a need to identify risky factors by monitoring the behavior of construction workers. Computer vision (CV) technology, which is a powerful and automated tool used for extracting images and video information from construction sites, has been recognized and adopted as an effective construction site monitoring technology for the identification of risky factors resulting from the unsafe behavior of construction workers. In this article, we introduce the research background of this field and conduct a systematic statistical analysis of the relevant literature in this field through the bibliometric analysis method. Thereafter, we adopt a content-based analysis method to depict the historical explorations in the field. On this basis, the limitations and challenges in this field are identified, and future research directions are proposed. It is found that CV technology can effectively monitor the unsafe behaviors of construction workers. The research findings can enhance people’s understanding of construction safety management.

Recent advances in the use of computer vision technology in the quality assessment of fresh meats

The computer vision direction in the field of artificial intelligence analyses the latest progress of computer vision technology from visual perception and visual generation, including but not limited to image recognition, target detection and image segmentation. First of all, for computer vision technology, this paper introduces the detailed application of image recognition technology, object detection technology and image segmentation technology. Then, we build a BP neural network combined with a deep LSTM neural network, use the BP network algorithm to select the input variables to reduce the dimension and complexity of the model, and use the selected variables as the input of the deep LSTM network. At the same time, deep LSTM is used to perform high-dimensional deep memory learning features on the selected variables. Finally, the model is separately experimented in computer vision. The experimental results show that the present model and other single models can be selected by BP neural network variables in computer vision applications, which can effectively reduce the complexity of the model and improve the generalisation ability of the model, so that it can be used in computer vision research.

This case-history paper presents details for a health, safety, and environmental (HSE) program, jointly developed by a service company and an oil company as part of an advanced, software-controlled, composite coiled-tubing, offshore drilling system. This drilling system can enable oil companies to economically harvest known hydrocarbon zones that were previously bypassed and to find and exploit new reserves. From the feasibility study forward, the latest HSE standards were incorporated into all phases of the project. The resulting Global HSE Program allowed access to the knowledge and experience of professionals from all parts of both organizations. This paper provides a detailed description of the national, cultural, engineering, and logistical challenges overcome during the development of the HSE Program. The paper also illustrates how teams from design, manufacturing, operations, maintenance, technical safety, HSE, quality verification, and management were unified for delivering a safe product. Included is an overview of the specific requirements necessary to fully define the unit for deployment in the Norwegian sector. The Historic Background HSE processes are often viewed as tasks that must be performed to satisfy customers and legislators. Despite the best intentions of the senior members of the corporate body, the non-HSE personnel who work within the projects sometimes consider HSE processes constraining. However, times are changing, and many HSE professionals are starting to appreciate the benefits of a well-conceived and constructive HSE program. For many projects, a formal, rigid hazard identification/risk management process is essential because the first time that equipment is fully assembled and functional is in an operational environment with hydrocarbon contact. A similar hazard identification and risk management program was implemented in the advanced well-construction system (AWCS) project. The difference was that this project had the benefits of full testing of individual components, evaluation of the test program in a test well, and a complete function test of assembled components before offshore deployment. The designers, maintenance personnel, and equipment operators could exchange ideas and see the equipment perform in a controlled, risk-free environment. As a result, modifications were agreed upon and made within the early HSE program stages, optimizing equipment safety.1 An Introduction to AWCS In 1997, a service company and an oil company began jointly evaluating technologies that could be used to develop a revolutionary coiled tubing (CT) well-intervention system. This system, which will be deployed initially in the Norwegian sector of the North Sea, sets a new standard for drilling, whether conventional drilling rigs or CT drilling units are used. The system is centered around a new advanced composite coiled tubing (ACCT) with embedded wires that enable the geological steering of complex, extended-reach wellpaths that were not previously achievable. The system includes three major subsystems, digitally controlled and automated surface equipment, 2 7/8-in. ACCT with embedded wires, and the drilling and intervention bottomhole assembly (BHA). The hostile environment of the North Sea presents a number of offshore drilling challenges. The Norwegian government and the Norwegian oil company emphasize safety, and their statutory HSE requirements for offshore wells are among the most stringent in the oil and gas industry.

The earliest lease for oil prospecting was granted in 1865, and the first bore went down in 1866. Since then and up to 1936, 130 wells were drilled mainly in Taranaki, the East Coast of the North Island and the West Coast of the South Island. No commercial field was discovered, but some oil and gas was found sporadically — sometimes enough for local small-scale consumption — which kept interests alive. The Petroleum Act in 1937 vested all petroleum prospecting and mining rights in the Crown; with minor modification, it has regulated exploration to the present day. The war-time years saw renewed activity by several major companies; the first seismic surveys were undertaken, and some 20 holes were drilled. But except intermittent, small production from the Moturoa field in New Plymouth (the she of the first well of 1866), no further success was achieved and exploration ceased after 1944. The present period of activity started in 1955. On land the Kapuni gas-condensate field was discovered in 1959, and offshore the much larger Maui field in 1969. Both are in the Taranaki Basin which, having the best prospects in the country, has also received far more attention than other areas. Land operations sharply decreased after 1965 when Shell and BP, the only majors with on-land interests, began concentrating on new offshore holdings while still retaining their original big land concessions. Amongst the increasing number of independents continued regrouping of interests, farm deals, etc., have become common, and these companies account for nearly all activity on land during more recent years. Practically all drilling after 1965, which from a 5,686 ft. low in 1966 increased to 28,741 ft. in 1969 and 16,952 ft. in 1970 (the smaller 1970 figure is mainly due to rig shortage), was done by companies other than Shell-BP, many of them newcomers. Since to these the more promising prospects have been unavailable, exploration has noticeably shifted to areas of lesser and even marginal prospects. Concessions have for a number of years covered all lands of even remotest possibilities; the total area leased is around 50,000 sq. miles. Offshore the first concessions were granted in 1965; in 1970 they covered 384,547 sq. miles. Extensive geophysical surveys followed nearly immediately, and the first well was spudded by Esso in October, 1968. The second well, by Shell in March, 1969, discovered the large Maui field, later confirmed by two step-outs. Up to November 1970, 10 offshore wells with an aggregate footage of 101,181 ft. were drilled. I he only offshore rig now has left but additional targets are already established, and more will undoubtedly be after seismic surveys presently in course. Offshore drilling is expected to resume as soon as possible, particularly in concessions soon to expire. In large areas only recently granted, however, excessive water depth of up to 1000 m will prevent drilling for probably many years. On land, the tendency for wider participation in joint ventures is likely to continue. Increased activity by small operators is expected, as domestic rig availability has improved and many concessions are nearing expiry date. New licences to be granted over Greymouth and Canterbury areas which have drawn many competing applications should further stimulate the picture. Since Shell-BP in 1970 finally farmed out their large block in Taranaki which still holds the best prospects and many unexplored features, new operations are expected also there before expiry in 1973; BP-Shell's East Coast holdings expire in 1972 and the future of these two blocks which since 1955 have been in the hands of the same consortium, will probably be most important to further developments in New Zealand.

The ocean harbors vast potential for oil and gas resources, positioning offshore drilling as a critical approach for future energy exploration. However, high-temperature and high-pressure offshore reservoirs present formidable challenges, as conventional water-based drilling fluids are prone to thermal degradation and rheological instability, leading to wellbore collapse and stuck-pipe incidents. Offshore oil-based drilling fluids (OBDFs), typically water-in-oil emulsions, offer advantages in wellbore stability, lubricity, and contamination resistance, yet their stability under extreme high-temperature conditions remains limited. This study reveals the enhancement of offshore OBDFs performance in harsh conditions by employing nano-SiO2 to synergistically improve emulsion film stability and non-Newtonian rheological behavior while systematically elucidating the underlying mechanisms. Nano-SiO2 forms a composite film with emulsifiers, reducing droplet size, enhancing mechanical strength, and increasing thermal stability. Optimal stability was observed at an oil-to-water ratio of 7:3 with 2.5% nano-SiO2 dispersion and 4.0% emulsifier. Rheological analyses revealed that nano-silica enhances electrostatic repulsion, reduces plastic viscosity, establishes a network structure that increases yield stress, and promotes pronounced shear-thinning behavior. Macroscopic evaluations, including fluid loss, rheological performance, and electrical stability, further confirmed the improved high-temperature stability of offshore OBDFs with nano-SiO2 at reduced emulsifier concentrations. These findings provide a theoretical basis for optimizing offshore OBDFs formulations and their field performance, offering breakthrough technological support for safe and efficient drilling in ultra-high-temperature offshore reservoirs.