Cross-border petroleum geology in the North Sea: an introduction

The North Sea has entered a phase of infrastructure-led exploration in an attempt to extend the economic lives of the main fields and arrest the overall production decline to a certain extent, while the transition to a future low-carbon use of the basin is also in progress. As the papers in this volume demonstrate, in order to find, appraise and develop the mostly smaller near-field opportunities as well as making sure to grasp the opportunities of the near-future energy transition, a regional understanding of the North Sea is still critical. Even more so, a cross-border approach is essential because 1) some of the plays currently being targeted have a clear cross-border element, 2) it allows the comparison of stratigraphic names throughout the entire basin and 3) it enables explorers to learn lessons from one part of the rift to be applied somewhere else.This volume offers an up-to-date, ‘geology-without-borders’ view of the stratigraphy, sedimentology, tectonics and oil-and-gas exploration trends of the entire North Sea basin. The challenges associated with data continuity and nomenclature differences across median lines are discussed and mitigated. Examples of under-exploited cross-border plays and discoveries are discussed.

Worlds First Offshore Horizontal Well Using Jointed Pipe Cemented Frac Sleeve Technology

The Valdemar field, located in the Danish sector of the North Sea, targets a Lower Cretaceous, "dirty chalk" reservoir characterized by low permeabilities of <0.5mD, high porosities of >20% and contains up to 25% insoluble fines. To produce economically the reservoir must be stimulated. Typically, this is by means of hydraulic fracturing. A traditional propped fracture consists of 500,000 to 1,000,000 lbs of 20/40 sand, placed using a crosslinked seawater-based borate fluid. The existing wells in the field are completed using the PSI (perforate, isolate, stimulate)1 system. This system was developed in the late 1980s as a way of improving completion times allowing each interval to be perforated, stimulated and isolated in a single trip and has been used extensively in the Danish North Sea in a variety of fields. The system consists of multiset packers with sliding sleeves and typically takes 2-3 days between the start of one fracture to the next. Future developments in this area now require a new, novel and more efficient approach owing to new target reservoir being of a thinner and poorer quality. In order for these new developments to be economical an approach was required to allow for longer wells to be drilled and completed allowing better reservoir connectivity whilst at the same time reducing the completion time, and therefore rig time and overall cost. A project team was put together to develop a system that could be used in an offshore environment that would satisfy the above criteria, allowing wells to be drilled out to 21,000ft and beyond in excess of coiled tubing reach. The technology developed consists of cemented frac sleeves, operated with jointed pipe, allowing multiple zones to be stimulated in one trip, as well as utilizing a modified BHA that allows for the treatments to take place through the tubing, bringing numerous benefits. The following paper details the reasons for developing the new technology, the development process itself, the challenges that had to be overcome and a case history on the execution of the first job of its kind in the North Sea, in which over 7MM lbs of sand was pumped successfully, as well as the post treatment operations which included a proof of concept in utilizing a tractor to manipulate the sleeves. Finally, the production performance will be discussed supported by the use of tracer subs at each of the zones.

Enhancements in Fracturing Fluid Engineering Reawakens a North Sea Giant

The Valhall field, operated by AkerBP, has been a major hub in the North Sea, on stream for thirty-eight years and recently passed one billion barrels of oil produced. The field requires stimulation for economical production. Mechanically strong formations are acid stimulated, while weaker formations require large tip-screenout design proppant fractures. Fracture deployment methods on Valhall have remained relatively unchanged since the nineties and are currently referred to as "conventional". Those consist in a sequence of placing a proppant frac, cleaning out the well with coiled tubing, opening a sleeve or shooting perforations, then coil pulling out of hole pumping the proppant frac. For the past few years, AkerBP and their service partners have worked on qualifying an adapted version of the annular coiled tubing fracturing practice for the offshore infrastructure - a first for the industry, which has been a strategic priority for the operator as it significantly reduces execution time and accelerates production. As with all technology trials, the implementation of this practice on Valhall had to begin on a learning curve through various forms of challenges. Whilst investigating the cause and frequency of premature screenouts during the initial implementation of annular fracturing, the team decided to challenge the conventional standards for fluid testing and quality control. Carefully engineered adjustments were made with regards to high shear testing conditions, temperature modelling, and mixing sequences, these did not only identify the root cause for the unexpected screenouts, but also helped create the current blueprint for engineering a robust fluid. Since the deployment of the redefined recipe, adjusted testing procedures and changes made to the stimulation vessel, there have not been any cases of fluid induced screenouts during the executions. The fewer types of additives now required for the recipe have lowered the cost of treatments and the lower gel loading leads to reduced damage in the fractures, thereby contributing to enhanced production over the lifetime of the wells. This paper describes the investigation, findings and the resulting changes made to the fluid formulation and quality control procedures to accommodate for high shear and dynamic wellbore temperature conditions. It discusses the rationale behind the "reality" testing model and, proves that significant value is created from investing time in thoroughly understanding fluid behaviour in the lab, prior to pumping it on large-scale capital-intensive operations. The study demonstrated that there is always value in innovating or challenging pre-conceived practices, and the learnings from this investigation significantly improved the track record for annular fracturing on Valhall, redefined fluid engineering for the North Sea and will inform future annular fracturing deployments on other offshore assets around the world.

Hydraulic Fracturing to Successfully Exploit Depleted Gas Reserves: A Case History from the North Sea

Hydraulic fracturing has been well established in the Southern North Sea (SNS) since the mid-1980s; however, it has typically been conducted as the final phase of development in new gas fields. One of these fields is Chiswick located in the Greater Markham area 90 miles offshore UK in 130 ft of water. Following an unsuccessful well repair of the multi-fractured horizontal well C4, it was decided to cost-effectively and expediently exploit the remaining pressure-depleted reserves near the toe via a single large fracture initiated from a deviated sidetrack wellbore designated C6. A deviated wellbore was chosen versus the original near-horizontal well to reduce well risk and costs and ultimately deliver an economic well. Several key challenges were identified, and mitigating measures were put in place. Modular formation dynamics tester data from the sidetrack open hole indicated the reservoir pressure gradient had depleted to 0.23 to 0.25 psi/ft, raising concerns about the ability of the well to unload the fluid volumes associated with a large fracture treatment. Wellbore deviation and azimuth with the associated potential for near-wellbore tortuosity would drive a typically short perforation interval (i.e., 3 ft). However, a compromise to mitigate convergent pressure loss in depletion was required, and the perforation interval was therefore set at 14 ft with provision made for robust step-down tests (SDT) and multi-mesh sand slugs. To further offset any near-well convergence pressure drop during cleanup, an aggressive tip screenout (TSO) proppant schedule, including a high concentration tail-in (12 PPA) with an aggressive breaker schedule, was executed to fully develop propped hydraulic width. Following formation breakdown and SDT to 40 bbl/min, the well went on near-instantaneous vacuum. Clearly, an extremely conductive feature had been created or contacted. However, upon use of a robust crosslinked gel formulation and 100-mesh sand, the bottomhole and positive surface pressure data allowed a suitable fracture design to be refined and placed with a large width, as evidenced by the extreme 2,309-psi net pressure development over that of the pad stage while placing 500,500 lbm of 16/30 resin-coated (RC) intermediate strength proppant (ISP) to 12 PPA. Although a lengthy nitrogen lift by coiled tubing (CT) was planned, the well cleanup response in fact allowed unaided hydrocarbon gas flow to surface within a short period. The well was then further beaned-up under well test conditions to a flow rate of approximately 26 MMscf/D under critical flowing conditions with a higher bottomhole flowing pressure than that of the original C4 well. Given the last producing rate of the original multiple fractured horizontal wellbore was 27 MMscf/D at a drawdown of 1,050 psi through two separate hydraulic fractures, then the outcome of this well was judged to be highly successful and at the limit of predrill expectations. This case history explains and details the rationale, methods, and techniques employed in well C6 to address the challenge of successful hydraulic fracture stimulation in a depleted formation. Challenges were addressed by combining a number of techniques, coupled with field experience, resulting in a highly productive well despite the relatively low reservoir pressure coupled with a limited time frame to plan and execute. These techniques are transferrable to other offshore gas fields in the region where reservoir depletion makes economic recovery difficult or indeed prohibitive.

Mapping silver eel migration routes in the North Sea

Recent developments in tracking technology resulted in the mapping of various marine spawning migration routes of the European eel (Anguilla anguilla). However, migration routes in the North Sea have rarely been studied, despite many large European rivers and hence potential eel growing habitat discharge into the North Sea. In this study, we present the most comprehensive map to date with migration routes by silver European eels in the North Sea and document for the first time successful eel migration through the English Channel. Migration tracks were reconstructed for 42 eels tagged in Belgium and 12 in Germany. Additionally, some eels moved up north to exit the North Sea over the British Isles, confirming the existence of two different routes, even for eels exiting from a single river catchment. Furthermore, we observed a wide range in migration speeds (6.8–45.2 km day−1). We hypothesize that these are likely attributed to water currents, with eels migrating through the English Channel being significantly faster than eels migrating northward.

Seismic Hazard Assessment for a Wind Farm Offshore England

Offshore wind has become a major contributor to reducing global carbon emissions. This paper presents a probabilistic seismic hazard analysis for the Sofia Offshore Wind Farm, which is located about 200 km north-east of England in the southern North Sea and will be one of the largest offshore wind farms in the world once completed. The seismic source characterization is composed of two areal seismic source models and four seismic source models derived using smoothed gridded seismicity with earthquake catalogue data processed by different techniques. The ground motion characterization contains eight ground motion models selected based on comparisons with regional data. The main findings are (1) the variation in seismic hazard across the site is negligible; (2) the main source controlling the hazard is the source that includes the 1931 Dogger Bank earthquake; (3) earthquake scenarios controlling the hazard are Mw = 5.0–6.3 and R = 110–210 km; and (4) the peak ground accelerations on rock are lower than for previous regional studies. These results could help guide future seismic hazard assessments in the North Sea.

Feasibility Study on Biomonitoring of Microplastics in Fish Gastrointestinal Tracts

Monitoring the occurrence and trends of microplastic contamination in the marine environment is key to establish microplastic (MP) data baselines, to work out policy mitigation measures, and to assess the effectiveness of waste regulations. To establish MP contamination baselines in the marine environment, marine biota species can be selected as monitoring matrices to track plastic pollution in the environment. The aim of this work was to evaluate the feasibility of biomonitoring MPs in fish gastrointestinal tract (GIT). A selection of suitable fish species was performed, based on species distribution, sampling effort, commercial value of species, sustainable development of fish populations, migration behaviour, and scientific evidence for occurrence of MPs in the fish GIT. Sampling and MP extraction protocols were developed and validated on fish GIT samples acquired in the Southern North Sea. The fish species selection protocol enabled the selection of ubiquitous distributed and non-endangered fish species relevant for MP monitoring in the North Sea. The fish GIT sampling protocol considered background contamination measures and sampling fillet as procedural blanks. Advantages and disadvantages of onboard dissection were discussed. The MPs extraction protocol was based on matrix digestion, density separation, and Nile red staining of particles followed by fluorescent microscopy observation. The confirmation of MPs identification and the analysis of the polymer composition was done using micro-Fourier transform infrared (μFTIR) spectroscopy. The MP analysis indicated a low number of MPs in the fish GIT. The mean number of particles per single fish GIT was 0.48 ± 0.81 (Nile red staining observations) to 0.26 ± 0.64 (corrected for background contamination). A power analysis (sampling effort) indicated that to detect significant differences, in a balanced-ANOVA type of analysis, between species and/or sampling areas, the sample size would require a minimum of 109 up to 370 individual fish. The feasibility of MP biomonitoring in fish GIT was assessed by a SWOT-analysis, which indicated that fish GIT is a suitable matrix for biomonitoring of MPs, but that the large number of samples needed to identify significant differences can be a major drawback. A potential implementation strategy for MP biomonitoring within Europe was suggested.