Pioneer shut in 8,000 BOE/D production in its West Panhandle field in Texas on 6 March due to a compression station fire. Planning to use idle compressors, production is expected to restart later this month or in early April. As compressor stations are added to the natural gas gathering and transmission networks, the potential noise issues are coming under increasing public scrutiny at the same time as regulations are being rolled back.
AUVs have evolved from an emerging technology with niche uses to a viable solution and an established part of operations in various marine sectors. Douglas-Westwood’s AUV Market Forecast considers the prospective demand for AUVs in the commercial, military and research sectors over the next 5 years. How Much Would You Spend To Develop a New Technology? The value of new technology, and its ROI, is examined. Understanding the value proposition is not a trivial matter.
Anadarko aims to maximize immediate short-cycle value through tiebacks and platform relocations in the Gulf of Mexico. This review of papers illustrates some of the innovative solutions used in the region. In maturing oil wells, oil production is often restricted as reservoir pressure depletes. Two case studies highlight the application of two-screw multiphase pump systems in to extend well life. Mature fields still have value, and technology can help to capture that value through increased efficiency and reduced costs.
Ashtead Technology has acquired Louisiana-based subsea equipment rental and cutting services specialist, Aqua-Tech Solutions, as part of the company’s international growth plans in the US. Aker Solutions and FSubsea have agreed to a joint venture, named FASTSubsea, to help operators increase oil recovery. Called Eelume, the underwater drone will perform subsea inspection, maintenance, and repair work. From its record high in 2014, purchases of subsea equipment and SURF fell around 50% until reaching a low in 2018. New data suggest that the subsea market will be a top-performing oilfield service segment.
After years of development, qualification and engineering, subsea compression technology is now a proven solution to increase the recovery factor for offshore gas developments. The first subsea compression system was installed at the Aasgard field in the Norwegian Sea, which was started up successfully on the 17th. of September 2015. This project represents an important milestone for the oil and gas industry, as apart from representing the successful developments of new subsea processing technologies, subsea compression also proves itself a viable alternative field development option to oil and gas operators.
The experience from Aasgard enables tomorrow’s subsea compression solutions. The basis is increased field recovery by subsea compression. In addition it opens for wells stream and deep water applications, as well as CO2 EOR.
This paper aims to share Aker Solutions’ experience on Aasgard Subsea Compression project, from the design and the project execution phases up to the operational phase, highlighting the key learnings from more than 50 000 hours of successful subsea operation.
In addition, the paper will also describe the ongoing development activities to optimize the compression system delivered for Aasgard, with particular focus on increased field recovery and unit size and weight optimization without requiring qualification activities of new technologies. This new generation of subsea compression system will extend the applicability of this technology to a much wider range of fields and offshore regions.
Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
The ‘Pseudo’ Dry Gas (PDG) subsea concept is being developed to dramatically improve the efficiency of subsea gas transportation by removing fluids at the earliest point of accumulation. The technology will increase the geographical reach from receiving gas terminals, allowing asset owners to prolong production life without the need for more expensive design solutions. This paper will provide an overview of the innovative technology, demonstrating that a 200 km plus tie back can be achieved, without compression.
Increasing the distance of subsea tie-backs increases the liquid inventory, with constraints on pipeline diameter for slug free flow. The PDG concept is based on a main gas line integrated with piggable gravity powered drain liquid removal unit and pumps (a smaller fluid line transports separated liquid). Multiple units are specified to drain liquids as they condense in the line, maintaining near dry service. Liquid free operation removes the constraint on pipeline diameter. Specification of a large diameter pipe (within installation limits) reduces backpressure on the wells, enhancing recovery. Minimum stable flow limits are removed, improving tail end recovery.
Current stranded gas development options (subsea compression, floating facilities, FLNG) generate a step change in costs which can make a project uneconomic. This is even more acute in mature and semi-mature basins where existing gas processing facilities / LNG terminals already exist offshore or onshore along with sunk costs from the exploration. A case study for a 185 km pseudo dry gas subsea tie-back to shore demonstrates the PDG concept feasibility. This result is used to argue that the PDG concept should be included in the suite of subsea processing options considered by Operators in early field development planning.
Egil Hustvedt, a platform manager, demonstrates the digital twin of the Aasta Hansteen field. Equinor reached another milestone in its digital transformation with today’s official opening of two new onshore support centers that will centralize much of its offshore exploration and production activities. Located in Bergen, the company says that the centers have already helped boost production and improve safety. The expectation is that the digitally enabled centers and their multidisciplinary staff will create more than $2 billion in new value from 2020-2025. The integrated operations center saw its first test in September as it was connected to the Grane, Gina Krog, and Åsgard fields.
Sadikhov, Emin (Equinor ASA) | Ramirez, Adriana Citlali (Equinor ASA) | Sigernes, Lill-Tove W. (Equinor ASA) | Aaker, Ole Edvard (AkerBP (Formerly Equinor ASA /Norwegian University of Science and Technology)) | Arntsen, Børge (Norwegian University of Science and Technology)
Summary When interpreting exploration and production datasets there can be uncertainty related to falsely identifying multiples as primaries. This can be experienced in exploration areas with limited well control and velocity information, and in more mature producing areas where we extract information from seismic data for drilling and production decisions. As a result, falsely interpreted multiples can affect both our structural and stratigraphic understanding as well as interfere with reservoir analysis, volume estimation and other relevant production decisions. This paper describes modeling of internal multiples using an inverse scattering series (ISS) algorithm and subsequent attenuation with an aim to improve data quality and quantitative understanding of Åsgard field Smørbukk. Introduction Generally, multiples can be subdivided into two main groups: free surface and internal multiples.
Subsea cooling in oil and gas production might seem to be opposite to the usual flow assurance challenge, maintaining a high enough flowing temperature of the produced stream in order to ensure problem free transport of the crude from well to the host. During FEED and detailed design, particular focus is aimed at maintaining a required temperature with insulation and even electrical heating are employed in order to achieve this. Hydrate formation, wax and asphaltene deposits are challenges that are connected with too low temperature, and considerable effort is spent in quantifying acceptable temperature, and cool down times of subsea equipment. So one might ask why and where is the need for subsea cooling? It turns out that there are situations where the well fluids are very warm and reduction in the temperature is required for profitable development of a field. For example, where an expensive flow line material would render the installation too costly, a reduction in temperature might make the investment evaluations look attractive, or where heat is generated subsea by for instance a subsea gas compressor. The temperature greatly affects the corrosion rate, and by changing the temperature, chemical dosage can be optimized, which further strengthens the financial analysis of a field development. This paper focuses on active subsea coolers, i.e. subsea cooling systems that are equipped with adjustable means, and attempts to analyze and benchmark four different subsea cooler types using a generic wet gas production case. A recent development involving a sea current controlled active cooler is introduced and compared with three other active cooler types and how they operate with a given set of operation and turndown conditions are presented. A comparison of weight, size, auxillary equipment and required topside scope is also included.