On offshore rigs, oil-based mud (OBM) cuttings can create logistical and environmental risks. Onshore disposal requires costly transport, and bad weather can halt shipping operations. The liability for waste treated onshore belongs to the operator. Although offshore disposal removes this liability, UK North Sea regulations specify that oil on cuttings (OOC) must be less than 1%. (by weight?) A rigsite thermomechanical cuttings cleaner (TCC) applies high temperatures to help reduce OOC to less than 1% and recovers base oil and water for reuse.
A TCC unit was installed on a semisubmersible rig to process OBM cuttings for a 24-well program. Mechanical action is applied directly to the cuttings by means of hammers that create friction, causing temperatures to exceed the boiling points of water and oil so that hydrocarbons are separated. The oil and water vapors are removed and condensed where the base oil and water are further separated and recovered. The TCC process on this rig was supported by vacuum-pump conveyance equipment and specialized storage tanks. Cuttings were no longer shipped to shore, and crane lifts associated with "skip-and-ship" operations were minimized significantly.
The TCC unit processed 14,500 metric tons (MT) of OBM cuttings throughout the duration of the 24- well program. The total footage drilled with OBM was more than 160,000 ft. All cuttings were disposed offshore. Approximately 13,500 bbl of base oil (valued at USD 135/bbl) was recovered for reuse in the drilling fluid system. The TCC unit ran for a total of 3,500 hours with zero downtime or nonproductive time (NPT) associated with cuttings disposal. The average is approximately 150 operating hours per well. One important benefit was the dramatic reduction of skips handling and crane lifts, which provided safer working conditions for rig crews. On a conventional skip-and-ship operation, the operator would fill and transport up to 35 skips per day. This translates to 2,380 crane lifts per well that were unnecessary. Offloading delays caused by bad weather were no longer a factor, thus helping reduce uncertainty and saving valuable rig time. Processing this volume of drill cuttings offshore meant that more than 57,000 skip crane lifts were avoided. The TCC mobilization process for this program was executed efficiently by coordinating with quayside contractors (welders, platers, electricians, etc.) to complete much of the installation work scope onshore.
Thermal treatment enables operators to address stringent offshore discharge regulations globally, excluding countries with zero discharge policies. Cost benefits include the following: No "wait on weather" time (rig day rate = USD 300,000) No dedicated vessels for transport No quayside cuttings handling No trucking to treatment and disposal facilities
No "wait on weather" time (rig day rate = USD 300,000)
No dedicated vessels for transport
No quayside cuttings handling
No trucking to treatment and disposal facilities
Safety and environmental benefits add the following value: Reduced manual handling of skips Reduced crane lifts Base oil reuse Liability for waste ends at rigsite
Reduced manual handling of skips
Reduced crane lifts
Base oil reuse
Liability for waste ends at rigsite
Dominic Perkins, BP Project Manager, Mergers and Acquisitions, recently gave a presentation to the Aberdeen ELP group on "Asset Acquisitions and Divestments--Learning From BP's North Sea Disposals." Asset acquisitions have contributed to BP becoming the number two oil company in the world. BP has increased in value from a U.S. $70 billion to approximately $200 billion company, and much of this is attributable to acquisitions. BP's strategy consists of four elements: Perkins explained acquisition and divestment terminology, walked the audience through the divestment process, and discussed associated issues. The three phases of the divestment process were explained in detail: marketing, sales, and purchasing agreement; execution/transition; and the project closeout.
Weijermans, Peter-Jan (Neptune Energy Netherlands B.V.) | Huibregtse, Paul (Tellures Consult) | Arts, Rob (Neptune Energy Netherlands B.V.) | Benedictus, Tjirk (Neptune Energy Netherlands B.V.) | De Jong, Mat (Neptune Energy Netherlands B.V.) | Hazebelt, Wouter (Neptune Energy Netherlands B.V.) | Vernain-Perriot, Veronique (Neptune Energy Netherlands B.V.) | Van der Most, Michiel (Neptune Energy Netherlands B.V.)
The E17a-A gas field, located offshore The Netherlands in the Southern North Sea, started production in 2009 from Upper Carboniferous sandstones, initially from three wells. Since early production history of the field, the p/z plot extrapolation has consistently shown an apparent Gas Initially In Place (GIIP) which was more than 50% higher than the volumetric GIIP mapped. The origin of the pressure support (e.g. aquifer support, much higher GIIP than mapped) and overall behavior of the field were poorly understood.
An integrated modeling study was carried out to better understand the dynamics of this complex field, evaluate infill potential and optimize recovery. An initial history matching attempt with a simulation model based on a legacy static model highlighted the limitations of existing interpretations in terms of in-place volumes and connectivity. The structural interpretation of the field was revisited and a novel facies modeling methodology was developed. 3D training images, constructed from reservoir analogue and outcrop data integrated with deterministic reservoir body mapping, allowed successful application of Multi Point Statistics techniques to generate plausible reservoir body geometry, dimensions and connectivity.
Following a series of static-dynamic iterations, a satisfying history match was achieved which matches observed reservoir pressure data, flowing wellhead pressure data, water influx trends in the wells and RFT pressure profiles of two more recent production wells. The new facies modeling methodology, using outcrop analogue data as deterministic input, and a revised seismic interpretation were key improvements to the static model. Apart from resolving the magnitude of GIIP and aquifer pressure support, the reservoir characterization and simulation study provided valuable insights into the overall dynamics of the field – e.g. crossflows between compartments, water encroachment patterns and vertical communication. Based on the model a promising infill target was identified at an up-dip location in the west of the field which looked favorable in terms of increasing production and optimizing recovery. At the time of writing, the new well has just been drilled. Preliminary logging results of the well will be briefly discussed and compared to pre-drill predictions based on the results of the integrated reservoir characterization and simulation study.
The new facies modeling methodology presented is in principle applicable to a number of Carboniferous gas fields in the Southern North Sea. Application of this method can lead to improved understanding and optimized recovery. In addition, this case study demonstrates how truly integrated reservoir characterization and simulation can lead to a revision of an existing view of a field, improve understanding and unlock hidden potential.
Recently two multilateral horizontal wells have been completed offshore using dedicated multistage hydraulic fracturing completions. The first well, located in the Central North Sea (referred to as ML-CNS), was stimulated using acid fracturing; while the second well, located in the Black Sea (referred to as ML-BKS), was stimulated using proppant fracturing. This paper presents the different drivers, challenges and lessons learned for each well while emphasizing the well construction and stimulation methodologies developed for the different reservoirs and field characteristics.
The field development drivers for drilling and completing these offshore hydraulic fractured multilateral wells, a first of their kind globally, was different for each case. The objective of the first project, initially considered uneconomic, was to engineer a technical solution for completion and production of two separate reservoirs with only one subsea well. The second project was seeking to optimize infill drilling from the last available slot on the offshore platform to maximize reservoir contact and production in the same reservoir. ML-CNS was a TAML Level 2 completion with a 14-stage, 5 ½" multistage completion run in each lateral and set-up for sequential acid fracturing. Operationally, the first lateral was drilled and stimulated, followed by the drilling and stimulation of the second lateral, using the drilling whipstock to navigate through the multilateral junction. ML-BKS was a TAML Level 3 completion that had a 6-stage, 4 ½" multistage completion installed in each lateral, which were proppant fractured following a sequence designed to minimize the jack-up rig time required. Both legs were drilled and completed prior to starting the stimulation, access to either lateral was achieved with the existing workover unit on the platform by manipulating a custom designed BHA.
The lessons learned from the first project executed in the North Sea were able to be transferred and applied to the second project in the Black Sea to allow for a more efficient and confident completion solution. Led by varying economical and regional constraints, the key factor for both wells centered on delivering operationally simple and reliable multilateral completion designs to economically meet the field development strategy in place.
To the knowledge of the authors and following subsequent literature research, both wells are a worldwide first for an offshore multilateral well completed with multistage acid fracturing and multistage proppant fracturing, and together they represent a new trend in cost-effective offshore field development through well stimulation. The successful case studies for both wells with the combined analysis of the benefits, challenges, and lessons learned will provide a guide and instill confidence with operators who find this approach beneficial with a view to applying it in other assets.
We all identify the need to integrate climate change into corporate strategy, with a profitable Carbon Capture Utilisation & Storage (CCUS) business model the elusive goal. Today, CCUS forms 10% of the R&D program of Total, a founding contributor to the OGCI Climate Investments fund. Here in the North East of Scotland, UK and Scottish Governments, along with project developer Pale Blue Dot Energy and Total are providing match funding to the European Commission’s Connecting Europe Facilities fund to progress feasibility work on the Acorn CCS project. As society continues to drive an expectation beyond hydrocarbons, what proposal might the North East of Scotland offer in response?
To meet ambitious emissions reduction targets, the UK must envisage radical changes to the energy economy. Already affecting power generation, these changes must drive further into transport and domestic/industrial energy consumption. Two technologies which may play a part in the decarbonisation of the UK energy business are CCUS and the use of Hydrogen as an energy carrier and energy store, with several studies showing that clean hydrogen is potentially the lowest cost route to meeting UK emission targets in multiple sectors. This builds on the UK’s world class gas network infrastructure, which can be repurposed to avoid becoming stranded, avoiding the enormous expense of increasing the capacity of the electricity transmission network, much of which would lie idle during the summer. The UK gas network carries approximately three times more energy than the electricity network, at one third the unit cost to consumers, and meets winter peaks that are five times greater.
Different to previous CCUS projects, and having the Oil and Gas Authority (OGA)’s first carbon dioxide appraisal and storage licence award, ACORN is an opportunity to evaluate a brownfield CCUS solution to capture, transport and store post-combustion CO2, combined with an upside through emerging pre-combustion CO2 capture technology relating to the production and sale of bulk hydrogen produced from natural gas with a zero-emission target. Located at the St Fergus Gas Terminal – an active industrial site where around 35% of all the natural gas used in the UK comes onshore. ACORN is designed as a "low-cost", "low-risk" CCUS project, to be built quickly, taking advantage of existing oil and gas infrastructure and well understood offshore storage sites. The Acorn Hydrogen project undertakes to evaluate and develop an advanced reformation process which will deliver the most energy and cost-efficient industrial hydrogen production process whilst capturing and sequestering CO2 emissions. An initial phase offers a full-chain demonstration project, an essential step toward commissioning the concept and subsequent commercialisation of large-scale CCUS and Hydrogen deployment in the UK.
SPE Offshore Europe represents an ideal opportunity to update both the region and industry on results, observations, and conclusions with respect to the evolving development architecture, selected process technologies, Government and gas transportation regulatory engagement as this, the leading Scottish CCS project continues its journey toward a final investment decision.
Several mature fields in the North Sea experience significant challenges relating to high pressures and temperatures accompanied with the infill drilling challenge of very narrow margins between pore and fracture pressures. To navigate these narrow mud weight windows, it is critical to understand the bottom hole pressure. However, in the cases of fractured formations above the target zones, severe losses can be encountered during drilling and cementing operations often leading to the inability to maintain a full mud column at all times and even threaten the ability to reach TD.
The operator therefore decided to investigate the use of a new acoustic telemetry system that could provide internal and external pressure measurements, (along with other downhole measurements) independently of traditional mud pulse telemetry in the drilling assembly. Real-time distributed pressure data essential to understanding the downhole conditions could therefore be provided regardless of circulation, even under severe losses or during tripping and cementing operations.
This acoustic telemetry network was deployed on several wells through multiple hole sizes and including losses management, liner running and cementing operations.
The initial primary purpose of running the network was the ability to monitor the top of the mud at all times, even in significant loss situations. As real-time data was acquired it became apparent that the data could also be used in real-time to aid and help quantify the actual downhole pressures. The use of this downhole data was modified and new calculations designed for simpler visualization of equivalent circulating densities at the shoe, bit and identified weak zones in the well at depths beyond the acoustic tools themselves. This data was used to manage the bottom hole pressure within a 300 psi mud weight window to ultimately enable the well to be delivered to planned TD.
The tool and calculations helped verify managed pressure connections and subsequent pump ramp up and down operations to minimize pressure fluctuations in the well. Additionally the data was used during dynamic formation integrity testing and to measure and calculate ECD at various positions along the drillstring and casing when downhole PWD measurements were unavailable.
This paper will describe how the implementation of new technology through the downhole acoustic network was deployed and the lessons learned in how the real-time data was used, changed and adapted in this particular well. Due to this deployment the acoustic telemetry network will now be used on upcoming equally challenging wells and its range of operations expanded to include drilling, tripping and liner cementing operations.
Understanding petrophysical properties well enough to make drilling decisions, particularly for tight gas can be a challenge. A new computer system aims to help analyze the extensive data involved. There are more than 100 accumulations in the southern North Sea that are flagged as stranded fields. One of these stranded tight gas fields, the Kew field, has been developed successfully with the use of a subsea well, horizontal drilling, and hydraulic fracturing.
A consortium of organizations has set out to tackle one of the more enduring challenges in the North Sea: the nondestructive testing (NDT) of corroded pipes under insulation and engineered temporary pipe wraps. General Electric has launched a subsidiary to develop and sell the use of flying, crawling, and swimming drones for inspections in the oil and gas industry, among others, the company announced.
An 18-month project will develop and trial a mobile robot for autonomous operational inspection of Total facilities. A consortium of organizations has set out to tackle one of the more enduring challenges in the North Sea: the nondestructive testing (NDT) of corroded pipes under insulation and engineered temporary pipe wraps. General Electric has launched a subsidiary to develop and sell the use of flying, crawling, and swimming drones for inspections in the oil and gas industry, among others, the company announced. Behind the use of most drones and unmanned aerial vehicles is the issue of safely and legally operating beyond the visual line of sight (BVLOS).
UK's First Carbon Capture and Storage Project Could Be Operational by Mid-2020s The Acorn Project will capture about 200,000 tonnes of carbon dioxide from the St. Fergus Gas Terminal and transport it for storage to one of three depleted gas fields using existing pipelines. Levels of stress and mental health problems among UK workers are at a 17-year high, according to the latest injury and ill health statistics published by the Health and Safety Executive. The UK’s offshore oil and gas industry continued to see improvement across a broad range of health and safety indicators last year, according to a key insight published by Oil & Gas UK. Offshore Industry Has Come'Perilously Close to Disaster,' Warns UK's Health and Safety Executive The Health and Safety Executive (HSE) has warned the UK’s offshore oil and gas operators that they must do more to tackle hydrocarbon releases in the North Sea after coming “perilously close to disaster” in recent years. Oil & Gas UK recently published guidelines with its most up-to-date information aimed at helping operators ensure they have the required financial measurements in place to meet the cost of cleanup for an oil release. North Sea oil and gas production was up but greenhouse gas emissions in 2016 were down against 2015 performance, according to Oil & Gas UK’s Environment Report.