Digitalization is the transformation of business models and activities through the strategic use of digital technologies. Despite technological advancements in machine learning (ML), artificial intelligence (AI), and virtual reality (VR), there remains a low maturity of digitalization across the oil and gas industry, especially in offshore operations. There are many roadblocks on the way to digitalization, from data silos to legacy systems. Operational inefficiency is one of the most painful byproducts of these problems.
To complete a single maintenance task, for example, on-site workers may need to access several separate systems to get the required data. They rely on printing out the information they need in order to complete the maintenance activities, and after taking notes on pieces of paper, they have to return to their desktop computer to log the performed tasks.
Not having the data readily accessible contributes to overall inefficiency, and offshore workers often run back and forth while performing maintenance tasks, increasing the hours they spend in challenging conditions.
This paper will outline an application design philosophy for oil and gas companies that combines academic and practical insights, an emphasis on continually testing products in development, and an overall goal of creating value.
This paper will describe how a Nordic software company is using the design philosophy to help an oil and gas operator in Northern Europe optimize on-site operations -- including increasing efficiency and safety -- on its offshore installations on the Norwegian Continental Shelf.
Specifically, the paper will show the software company ingested and contextualized operational data from the operator's assets and made historical data available for field workers via an application for computers and smart devices. This included access to sensor data and historic equipment performance data; all documentation related to maintenance, including procedures, drawings, piping and instrumentation diagrams (P&IDs), and maintenance logs; and interactive 3D models of installations and equipment.
After only three months, the crew at one of the operator's oil installations saw significant increases in the number of monthly maintenance jobs (up to 10% for certain tasks) and reduction of the time spent on certain routine inspections (in some cases up to 50%).
The last session is going to be a forward-looking discussion influenced from the key takeaways of the whole week. One last time we will have a common debate aiming for expanding the utilization of deep reading while revising the barriers we must overcome. Unresolved topics and gaps will be identified for providing recommendations to research and development. The closing session may also recognize topics that needs to be discussed in future SPE Forums.
The strategy supports the Maximise Economic Recovery from UK Oil & Gas Strategy and Vision 2035, whose goal is to achieve £140 billion additional gross revenue from UKCS production by that time. This paper demonstrates a new way to create gas-tight seals during well abandonment, overcoming the limitations of traditional methods and reducing the operator’s liability and potential environmental impact after decommissioning has been completed. This paper discusses studies conducted on two California offshore fields that may be abandoned in the near future. These studies examined the feasibility of repurposing these fields for offshore gas storage by using their reservoir voidage and existing pipeline facilities. The same tools that make it fun and easy for you to see a friend's updates online are also pretty good at tying together unconnected databases holding valuable well information.
A key aspect of the project discussed in this paper is the use of minimal initial-production facilities to achieve significant early production from each of four preconstructed artificial islands. Many offshore decommissioning costs are higher than necessary because of decisions made during the initial engineering and construction for an oil or gas field. With a high demand for plug and abandonment (P&A) of subsea wells in the future on the Norwegian continental shelf, industry is challenged to find alternatives and rigless technologies that can make P&A operation more cost-effective and -efficient.
The strategy supports the Maximise Economic Recovery from UK Oil & Gas Strategy and Vision 2035, whose goal is to achieve £140 billion additional gross revenue from UKCS production by that time. Visuray is using its unique X-ray technology to improve downhole imaging. A company is selling a new well testing tool designed to be a cheaper, simpler way to do fiber optic sensing, and then it fades away. BP has seen enormous payoff from a program to intervene in underperforming subsea wells in the Gulf of Mexico. A coiled-tubing selective perforating and activation system that transmits critical downhole data and measurements in real time is enabling well interventions that previously could not have been executed.
Designing a successful steamflooding project requires good candidate selection and an excellent understanding of the mechanisms by which recovery is enhanced. Screening criteria for identification of steamflood candidates have been published for many years. Table 1 shows the screening guides from five different sources. It is obvious from Table 1 that there is a finite envelope of properties that define successful candidates. However, within that envelope there is a relatively wide spread of values for the indicators.
Relative permeability has important implications for flow of reservoir fluids. A number of models have been developed to relate relative permeability to other reservoir properties. This page provides an overview of those models. In 1954, Corey combined predictions of a tube-bundle model with his empirical expression for capillary pressure to obtain expressions for gas and oil relative permeabilities. In 1964, Brooks and Corey extended Corey's results using Eq. 1 for capillary pressure to obtain the following expressions for oil and gas relative permeabilities: Eqs. 2 and 3 apply to a porous material that is initially fully saturated with oil and then invaded by gas.
Water is the wetting phase. Figure 1.5 – Primary drainage, imbibition, and secondary drainage for an oil/water system in which the oil and water wet the solid surface equally. Figure 1.6 – Primary drainage and imbibition for unconsolidated dolomite powder (the lines merely connect the data). These authors wrote capillary pressure as the negative of Eq. 4 because oil was the wetting phase for most of the tests. The legend gives contact angles measured through the water phase (in degrees). Leverett and coworkers, based on the evaluation of gas/water capillary pressure data for drainage and imbibition in unconsolidated sands, proposed the following definition: ....................(15.6) The function j(Sw), defined in Eq. 15.6, is known to many as the "Leverett j-function." The j-function is obtained from experimental data by plotting against Sw. The combination is often considered an estimate of the mean hydraulic radius of pore throats.
Well control and blowout prevention have become particularly important topics in the hydrocarbon production industry for many reasons. Among these reasons are higher drilling costs, waste of natural resources, and the possible loss of human life when kicks and blowouts occur. One concern is the increasing number of governmental regulations and restrictions placed on the hydrocarbon industry, partially as a result of recent, much-publicized well-control incidents. For these and other reasons, it is important that drilling personnel understand well-control principles and the procedures to follow to properly control potential blowouts. Many well-control procedures have been developed over the years.
When combined with relatively mature subsea production technologies (see subsea chapter on well systems, manifold, pipeline, power and control umbilical, and so on), it can reduce development cost, enhance reservoir productivity, and improve subsea system reliability and operability. Over the period from 1970 to 2000, millions of dollars have been spent to develop subsea separation and pumping systems. But because of unresolved technical issues, along with a lack of confidence and clear understanding of the costs and benefits, industry has not rushed to deploy the technology on a commercial basis. However, as the industry moves into remote deep and ultradeep water, various degrees of subsea processing are becoming more common. In deep water, the technology can enable hydrocarbon recovery from small reservoirs that are subeconomic by conventional means, making small fields economically viable and large fields even more profitable. Subsea processing refers to the separation of produced ...