In recent years, the oil and gas industry has gained greater operational efficiencies and productivity by deploying advanced technologies, such as smart sensors, data analytics, artificial intelligence and machine learning — all linked via Internet of Things connectivity. This transformation is profound, but just starting. Leading offshore E&P operators envision using such applications to help drive their production costs to as low as $7 per barrel or less. A large North Sea operator among them successfully deployed a low-manned platform in the Ivar Aasen field in December 2016, operating it via redundant control rooms — one on the platform, the other onshore 1,000 kilometers away in Trondheim, Norway. In January 2019, the offshore control room operators handed over the platform's control to the onshore operators, and it is now managed exclusively from the onshore one. One particular application — remote condition monitoring of equipment — supports a proactive, more predictive condition-based maintenance program, which is helping to ensure equipment availability, maximize utilization, and find ways to improve performance. This paper will explain the use case in greater detail, including insights into how artificial intelligence and machine learning are incorporated into this operational model. Also described will be the application of a closed-loop lifecycle platform management model, using the concepts of digital twins from pre-FEED and FEED phases through construction, commissioning, and an expected lifecycle spanning 20 years of operations. It is derived from an update to a paper presented at the 2018 SPE Offshore Technology Conference (OTC) that introduced the use case in its 2017-18 operating model, but that was before the debut of the platform's exclusive monitoring of its operations by its onshore control room.
Kumar, Abhineet (Cairn Oil & Gas, Vedanta Limited) | Prakash, Aditya (Cairn Oil & Gas, Vedanta Limited) | Singh, Alok (Cairn Oil & Gas, Vedanta Limited) | Bharati, Pradeep (Cairn Oil & Gas, Vedanta Limited) | Jayan, Binshu (Cairn Oil & Gas, Vedanta Limited) | Kothiyal, Manish (Cairn Oil & Gas, Vedanta Limited) | Patil, Bhushan (Cairn Oil & Gas, Vedanta Limited) | Sarma, Phanijyoti (Cairn Oil & Gas, Vedanta Limited)
An offshore drilling campaign comprising of four development wells was conducted to augment oil production from a field located off the western coast of India. All four wells were designed to be sidetracked from existing depleted wells of the field. Historically, preparing existing wells in the field for side-track took ~4 days/well of a drilling rig and associated spread cost. This paper presents a case- history of conducting side-track well preparatory activities by a rig-less well intervention spread leading to significant time and cost savings. This method was also the first instance of such an activity being conducted in an offshore environment in India.
Prior to actual side-track drilling from an existing well in a brown field, it is required to abandon the open zones in the existing well and prepare the well for casing window cutting for further drilling to a new sub-surface target. Typical preparation activities include multiple wireline runs to set/retrieve deep set and tubing hanger plugs, well killing, nipple-down X-mas tree, nipple-up BOP, wireline run to cut tubing, retrieval of existing completion and ultimately placement of cement plugs to abandon the parent wellbore. The routine approach in the organization for all previous offshore drilling campaigns was to utilize the offshore drilling rig for afore-mentioned well preparation activities. Substantial rig time was spent incurring the cost of entire rig spread for an average ~4 days/well equivalent to ~40% of total well completion time.
The paper elaborates on rig-less operations set-up consisting of Cementing and Wireline Units utilized to conduct well killing, placement of cement plugs, production tubing cutting and nippling down X-mas tree prior to the mobilization of the drilling rig at the platform. The only operation left for the drilling rig was to pull-out the existing completion string and then drilling operations could commence.
The execution of planned operations was flawless on three wells while one well posed technical limitation due to its high deviation. The rig less well preparation campaign was concluded incident free, ahead of schedule and within budget. This offline exercise prior to rig-move saved ~12 days of drilling campaign time which helped in cutting down on overall drilling campaign cost and also allowed the flexibility of adding more wells to the campaign within fair weather window.
While this was an effort to simplify operations and save costly drilling rig-time in a side-track drilling campaign by conducting some very critical operations offline, these methods can also be adopted for planning well abandonment and decommissioning activities in a mature field.
Polymeric scale inhibitors used for scale squeeze treatments to control downhole inorganic scale don't perform well when pumped into the reservoir due to the poor adsorption properties on the rock surface. However polymeric inhibitors are more temperature stable than phosphonates and have higher tolerance to elevated cation compositions in the water. Therefore, a new chemistry composed of metal nanoparticles coupled with a polymeric scale inhibitor was developed to improve the squeeze life.
The use of nanoparticles in the oilfield has increased in recent years; this development shows how nanoparticles can be used to increased surface area and retention of scale inhibitor in the reservoir. Metal nanoparticles were selected because of their low environmental toxicity and low formation damage potential during injection and flowback.
A fast and efficient synthesis method was developed to create a novel chemistry that couples nanoparticles with polymeric inhibitors to produce a product that it was hoped would have excellent squeeze properties in multiple rock permeabilities and compositions.
Core flood experiments were conducted on intact core under onshore Permian conditions of temperature pressure and brine composition as well as conditions simulating an offshore conventional field (results will be reported separately). The experimental results will be presented to show the extended squeeze lifetime of the new product in comparison to a traditional polymeric scale inhibitor retained by adsorption and also will give insight into the mechanisms by which the nanoparticle/scale inhibitor enhances squeeze life, both by increased adsorption as well as prolonging release of scale inhibitor.
The product developed is able to significantly increase the squeeze life of polymeric scale inhibitors by up to 10x depending on the minimum inhibitor concentration required. The retention of the inhibitor into the rock is significantly increased, while the release is controlled at above minimum effective concentration for extended periods. The theoretic explanation for this is a metal-inhibitor bond, proprietary to the product that allows for continuous release of inhibitor into the solution, without release from the rock. Traditional squeeze returns have a Freundlich isotherm, this product also follows a similar return curve, however does not suffer from the high concentration release at the beginning of the treatment flowback.
These results show that nanoparticles can be used in the oilfield to enhance existing scale inhibitors as well as create new combination products that can improve performance. Use on nanoparticles in the oilfield is an evolving topic that has significant room to grow and expand into multiple areas of oilfield chemistry. This study showcases the application of nanoparticles to enhance performance of polymeric scale inhibitors for squeeze application while maintaining a cost effective product that is environmental responsible.
Radzuan, Nurul Asyikin M. (PETRONAS) | Salleh, Nurfarah Izwana (PETRONAS) | Chandrakant, Ashvin Avalani (PETRONAS) | Rusman, Liyana (PETRONAS) | Zamanuri, Kautsar (PETRONAS) | Bakar, Azfar Israa Abu (PETRONAS) | Yip, Pui Mun (PETRONAS) | Jamaluddin, M. Helmi (PETRONAS) | Ghonim, Elsayed Ouda (PETRONAS) | Nambiar, Vijay (Novomet) | Alexander, Euan (Artificial Lift Solutions)
Following the first pilot success of the truly rigless 3-1/2" tubing cable deployed ESP (TTESP-CD in offshore field of Sarawak Basin, PETRONAS has taken steps to further advance in the technology development and application through more replications within Sarawak and Malay Basin. PETRONAS had been looking into a strong business case for the TTESP-CD technology for a wider application throughout Malaysia region by looking at fields with strong/moderate water drive and low bubble point pressure besides having other limitations on the platform including the facilities reliability issues. TTESP-CD are to be applied widely in Malaysia with more flexibilities in design and improvement towards the subsurface equipment, installation equipment and procedures. With the challenges in the existing completion and production requirement for replications, based on the lesson learnt from the pilot implementation, multiple improvements to the system have been done including; 1) A High Rate Slim Pump with Flexible Application 2) Alignment Tool for Cable Hanger Orientation. With this in place, more opportunities identified for the candidate selection which improve the installation philosophy specifically in dual string applications and enhance the efficiency in installation procedures. Case studies of TTESP-CD replications in Malay & Sarawak Basin for Field T, Field B and Field P presenting the best case for TTESP-CD application with improvement to design, equipment and application. These will bring additional value to PETRONAS with estimated production gain of 1.5 KBD and up to 1.2 MMSTB reserves to be monetized with additional value saving of up to RM 6 Mill. Besides the subsurface challenges, aging offshore assets brings a lot of challenges, especially on the space availability, structural integrity, power availability and distribution, instrumentation and data transmission. This requires an integrated approach from multiple disciplines in delivering the studies as per required within the targeted timeframe.
Mohd Ali, Siti Syareena (PETRONAS Research Sdn Bhd) | Teng, Kevin Ging Ern (PETRONAS Research Sdn Bhd) | A Jalil, M Azran (PETRONAS Research Sdn Bhd) | Sedaralit, M Faizal (PETRONAS Research Sdn Bhd) | Trianto, Adi (PETRONAS Research Sdn Bhd) | Wan Sagar, Siti Fatimah Sarah (PETRONAS Research Sdn Bhd)
The scope of the geomechanical study is to investigate the risk associated with different reservoir depletion strategies and to numerically simulate the geomechanical response of the reservoir rocks. The study focused on the large karstic distribution of the reservoir for the prediction of the best drilling direction and optimum well trajectories, and also to model the pore collapse behavior observed in the high porosity carbonate which will result in surface subsidence and impact the platform facilities placement.
A methodological risk evaluation approach based on numerical simulations with stringent experimental programme has been applied to the field study. The regional geological understanding and operational experience of the nearby fields have been considered for the study via extensive assessment of constitutive models relating to pore collapse. Advanced 4D geomechanical simulations were carried out to incorporate the seismic-based karstic models and to strengthen understanding of the pore collapse phenomena during reservoir depletion. The obtained prediction results were compared to nearby fields and subsequently use for wells, facilities planning and engineering considerations.
The results obtained in the study identified a few key outcomes which are being considered for detailed surface engineering design and well planning. The results have impacted the decision to place the location of the platform away from the center of the seabed subsidence bowl. The predicted reservoir compaction and subsidence described the rate and the magnitude of the subsidence which are use to design the height of the platform to mitigate potential damage induced by wave deck shearing. In addition, the distribution of karst has been mapped through seismic imaging and incorporated in the geomechanical modelling. The results are also used to determine the hazard of the weak zones in each formation and high stress anisotropy regions which are to be avoided for future well placement and to be used for well trajectory optimization. Key findings of the geomechanical-related risk have been identified and considered in the field development plan. Consequently, a Risk Ranking Criteria incorporating the results of advanced simulations and rock testing programme have been developed based on comprehensive weightage and the technical categories.
The paper offers a detailed insight on the geomechanical risk evaluation obtained using 4D finite element coupled reservoir geomechanical simulations. The study addressed the challenging development of a highly karstified limestone reservoir by offering valuable inputs for the well design and facility engineering through prediction of reservoir compaction and seabed subsidence, best drilling direction and optimum well trajectories. This will avoid potential geomechanical related hazards and ensure adequate operational safety levels.
Khan, Muhammad Hanif (Independent) | Maqsood, Tahir (Tullow Pakistan) | Jaswal, Tariq Majeed (Pakistan Oilfield Ltd) | Mujahid, Muhammad (Spec energy DMCC) | Malik, M. Suleman (Qatar Petroleum) | Jadoon, Ehtisham Faisal (UEP Pakistan) | Hakeem, Uray Lukman (Qatar Petroleum)
This article investigates the seismic reflection geometries (possible reservoir) of Paleogene of Offshore Indus Basin Pakistan (shelf area) from 2D seismic and make an analogue with the proven carbonate reservoir geometries found in countries such as Canada and Middle East. The 2D seismic data are used to interpret the possible carbonate features and methods to identify them and define its depositional setting on the carbonate platform. The offshore Indus Basin is tectonically a rift and a passive continental margin basin, located in Offshore Pakistan and Northwest India where carbonates were deposited on the shelf and the deep offshore area during early post-rift phase. In the deep offshore area, carbonates were set on volcanic seamounts during the Paleogene age. In Paleogene, the Indian Plate was passing through the equator in the conditions of warmer water with appropriate water salinity, where those conditions were suitable for the growth of organisms responsible to develop reefs in the Offshore Indus area. The available seismic data analysis has indicated the possible presence of different carbonate reefs on the shelf. The seismic data enabled to define the possible carbonate Rimmed shelf depositional model in the area. The aim of this article is to highlight and analogue carbonate seismic geometries, their internal architecture in the Paleogene interval of the Offshore Indus Basin (shelf area) and how to identify them, which may help for further exploration in Offshore Indus Basin.
Shi, Hongfu (China National Offshore Oil Company) | Yue, Baolin (China National Offshore Oil Company) | Luo, Xianbo (China National Offshore Oil Company) | Shi, Fei (China National Offshore Oil Company) | Xiao, Bo (China National Offshore Oil Company)
The exploration and development of offshore oilfield facing unprecedented challenges include the decline in the quality of oil reserves, increase of invest and strict environmental protection policies. Usually, low permeability reservoir, heavy oil reservoir complex fault block and small reservoir located far from an existing facility are classified into marginal oilfield. More and more marginal oilfield is put on the schedule of development. In the view of economic, The internal rate of marginal oilfield return is lower than the benchmark rate of return of the industry, but higher than the cost discount rate of the industry. An integrated work flow is presented to improve the tap the potential and mitigate the risk of marginal oilfield involved in dependent development of small oilfields, unit exploitation of small oilfield group, simple platform, extended reach well and phased development. The LD oil field is taken as an example to state the strategy of marginal oilfield.
Zhao, Jianzhong (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | He, Jun (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | He, Yong (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | Sun, Pingtao (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | Li, Yanbo (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | Chen, Hongliang (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | Zhang, Shengliang (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | Guo, Yu (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company)
Objectives/scope: The poor quality of resources, low utilization of reserves,high investment in capacity building are the main problems faced in low permeability reservoir in Jilin Oilfield.The objective of this research is to form a intensive drilling model of large platforms which can improve the drilling quality,efficiency and management level. By applying this model,we can increase the single well production,block recovery rate and reduce the production construction investments,the development and production costs in low permeability oilfield. Methods,Procedures,Process: This research based on the production capacity construction in the Jilin Oilfield.This drilling model is different from the traditional model which is inefficient and the investments are higher.Our main procedures included the drilling plan optimization,intensive drilling application,efficient drilling technology application and drilling production management optimization. From 2015 to 2017,we have applied this drilling model successfully in Jilin Oilfield. Result,Observations,Conclusions: 1 Drilling Plan Optimization Technology The single well and small platforms are commonly used in the reservoir development of Jilin oilfield. Because of the low oil price,we changed our train of thought from traditional development mode to intensive drilling model of large platforms large platforms.It can reduce the land occupation area of well sites,reduce integrated management costs,and improve economical benefits of development effectively.By applying the lowest costs of investment principles,drilling engineering formed integrated drilling plan optimization technology which satisfied the requirements of geological deployment,fracturing and lifting,ground engineering,intensive drilling,economical development.It formed the platform size optimization technology that determined the most economical well number of the platforms.The oil field development investments contain 6 main parts,including drilling engineering,mud log engineering,logging engineering,oil recovery engineering,surface construction engineering and land occupation investments.With the increasing of the platform scale,the investments of drilling engineering increases,because the costs of drilling bits,drilling mud,casing,cement increase,which caused by the increasing of the well depth.The increasing of mud log 2 IPTC-19374-MS
Yang, Xudong (Baker Hughes, a GE company) | Bello, Oladele (Baker Hughes, a GE company) | Yang, Lei (Baker Hughes, a GE company) | Bale, Derek (Baker Hughes, a GE company) | Failla, Roberto (Baker Hughes, a GE company)
The Oil and Gas (O&G) industry is embracing modern and intelligent digital technologies such as big data analytics, cloud services, machine learning etc. to increase productivity, enhance operations safety, reduce operation cost and mitigate adverse environmental impact. Challenges that come with such an oil field digital transformation include, but are certainly not limited to: information explosion; isolated and incompatible data repositories; logistics for data exchange and communication; obsoleted processes; cost of support; and the lack of data security. In this paper, we introduce an elastically scalable cloud-based platform to provide big data service for the upstream oil and gas industry, with high reliability and high performance on real-time or near real-time services based on industry standards. First, we review the nature of big data within O&G, paying special attention to distributed fiber optic sensing technologies. We highlight the challenges and necessary system requirements to build effective and scalable downhole big data management and analytics. Secondly, we propose a cloud-based platform architecture for data management and analytics services. Finally, we will present multiple case studies and examples with our system as it is applied in the field. We demonstrate that a standardized data communication and security model enables high efficiency for data transmission, storage, management, sharing and processing in a highly secure environment. Using a standard big data framework and tools (e.g., Apache Hadoop, Spark and Kafka) together with machine learning techniques towards autonomous analysis of such data sources, we are able to process extremely large and complex datasets in an efficient way to provide real-time or near real-time data analytical service, including prescriptive and predictive analytics. The proposed integrated service comprises multiple main systems, such as a downhole data acquisition system; data exchange and management system; data processing and analytics system; as well as data visualization, event alerting and reporting system. With emerging fiber optic technologies, this system not only provides services using legacy O&G data such as static reservoir information, fluid characteristics, well log, well completion information, downhole sensing and surface monitoring data, but also incorporates distributed sensing data (DxS) such as distributed temperature sensing (DTS), distributed strain sensing (DSS) and distributed acoustic sensing (DAS) for continuous downhole measurements along the wellbore with very high spatial resolution. It is the addition of the fiber optic distributed sensing technology that has increased exponentially the volume of downhole data needed to be transmitted and securely managed.
This paper discusses the application of IIoT in various areas of oil and gas upstream. It elaborates on the drivers of IIoT, presents the advantages and benefits and describes the challenges faced as of today in the implementation. IIoT and cloud computing work hand in hand. IIoT generates huge amount of data and cloud computing provides a pathway to present this data is a useful way and travel to the end user. A detail evaluation of the investment in using this technology and its anticipated returns are demonstrated. IIoT is believed to be an emerging solution for oil and gas complexities. The main drivers behind this technology are data storage, data analytics, reliability improvement and materiality assessment and control. The application of IIoT in areas of artificial lift optimization, Supply chain in real time, cyclic steam stimulation and flow assurance is described. This technology provides real time solution for dynacards interpretation and analysis for Sucker rod pumps, operating point analysis for Electrical submersible pumps and predicted cumulative production for all artificial lift optimization; efficient planning and waste elimination for supply chain and logistics; real time steam quality and quantity check for CSS and a complete digital approach to reservoir management and flow assurance. The main benefits of this technology are reduced MTBF, high efficiency, improved HSE standards, Instantaneous control over production loss, collaborative decisions leading to fast turnaround, highly responsive supply chain and enhancing environmental footprint. This has helped substantially in real time management of wells by exception and alerts in form of intelligent alarms indicating any deviation in the expected behaviour. This has significantly brought down the non-productive time (NPT). However, this paradigm shift comes with a substantial cost. The technical challenges include the data security, protocol non-uniformity, possible data loss and limitations of redundant system.