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Drilling depleted reservoirs is fraught with a host of technical and economic problems that often make it unprofitable to further develop some mature fields. Most of the problems center around uncontrollable losses and differential sticking. Frequently, less expensive drilling fluids will be used in a particular interval, even though it may have the propensity to damage the formation. The reasoning holds that such fluids will offset the high costs of losing more expensive muds to the formation. If operators turn to underbalanced drilling as an alternative, the extra time and equipment required for a safe operation can seriously degrade project economics in some applications. A specialized invasion-control drilling fluid has been developed to drill reservoirs prone to lost circulation. This fluid combines certain surfactants and polymers to create a system of micro-bubbles or aphrons that are encapsulated in a uniquely viscosified system. Aphron based systems are engineered drilling fluids that aid in well construction by controlling losses in depleted, high-permeability sands while stabilizing pressured shales or other formations. One of the more attractive features of an aphron-based system is that it does not require any of the extra equipment used in air or foam drilling. There are no compressors, high-pressure hoses or connections to add costs and safety concerns. The system uses conventional fluid-mixing equipment to form tough, flexible micro-bubbles. This paper describes the development and application of the specialized micro-bubbles-based drilling fluid for controlling downhole mud loss in a depleted reservoir in the North Sea. The key issues of this project were excessive overbalance drilling conditions (> 5,000 psi) leading to the risk of highly expensive lost circulation and open perforations in the upper producer, requiring temporary sealing during drilling. The well was successfully drilled to TD without any drilling fluid losses. The authors will detail the laboratory methods used to generate appropriate formulations, the operational procedures, and field application. Introduction The drilling problems associated with the depleted reservoirs intrinsic to many of the mature fields throughout the world often make further development uneconomical. The water-wet sands that typify many of these zones propagate seepage losses and differential sticking, both of which are extremely expensive to correct. Uncontrollable drilling fluid losses frequently are unavoidable in the often large fractures characteristic of these formations. Furthermore, pressured shales are often found interbedded with depleted sands, thus requiring stabilization of multiple pressured sequences with a single drilling fluid. Drilling such zones safely and inexpensively is very difficult with conventional rig equipment. Such problems have led some operators to forgo continued development of these promising, yet problematic, reservoirs.1 Excessive overbalance pressure generated when using conventional drilling fluids is thought to be the primary cause of lost circulation and differential sticking when drilling these wells. The equipment required to manage aerated muds or drill underbalanced is often prohibitively expensive, and meeting safety requirements can be an exhaustive effort. Furthermore, these techniques may fail to provide the hydrostatic pressure necessary to safely stabilize normally pressured formations above the reservoir. Recently, a new drilling fluid technology based on aphrons - uniquely structured micro-bubbles — was employed to successfully drill a depleted reservoir in the North Sea. The use of aphron-based drilling fluids has proven to be a successful and cost-effective alternative to drilling underbalanced. Description of Aphron Structure An aphron comprises two fundamental elements2:A core that is commonly, but not always, spherical. Typically, the core is liquid or gaseous.A thin, aqueous, protective shell with an outer hydrophobic covering. The aqueous shell contains surfactant molecules positioned so that they produce an effective barrier against coalescence with adjacent aphrons.

In mature fields, hydrocarbons may become "trapped" below the main production zones. These overlying formations may be produced to a very low pressure, while the smaller trapped reserves may remain at virgin pressures or be slightly depleted. Drilling the depleted reservoirs requires a low mud weight to prevent losses and avoid either lower reservoir influx or shale collapse. Due to the often marginal size of the trapped reserves, reducing well costs is critical to project economics. One obvious solution is to deepen an existing producing well and commingle the production from the reservoirs, thus reducing cost when compared to a new dedicated well. Three novel technologies have been identified that, when combined, would allow wells to be deepened at low cost and without severe losses. These include through-tubing drilling,aphron-based drilling fluid, and real time ECD modelling. This paper describes a project where these technologies were applied. Owing to the high-risk nature of the project and the need to protect existing production from the chosen well, in-depth planning and staged implementation of the new technologies were undertaken. A comprehensive risk management procedure was developed and careful testing and data gathering undertaken. The well was successfully executed within planned time. The authors will outline the theoretical and practical aspects of the technology selection criteria, risk management aspects, and how all these were combined to deliver a successful well. Introduction The near vertical (20° inclination) North Sea gas well was producing 200,000m3/day from the upper reservoir zone. The upper reservoir zone, which has been producing for more than 20 years, was depleted from original field virgin pressure of 366 bar to 50 bar. The target lay beneath this depleted reservoir with a thick (40m) claystone layer in between that contains intermittent sand lenses. Throughout most of this field the lower reservoir is below the gas water contact. Thus, the majority of the field only drains the upper reservoir zone. The only well that previously produced from the lower reservoir had watered out. Consequently, in order to avoid the water leg, the plan was to target the remaining reserves in an up-dip location. Therefore, only a relatively small amount of reserves are in the lower reservoir, especially when compared with reserves in the upper block. However, it was perceived that if the well could be deepened inexpensively, it would be an attractive project. The target reservoir had been drained by one production well until it had watered out after eight years of production. It was not clear exactly how much had been produced from this lower reservoir zone, but the pressure was believed to be ca. 250 bar. Additionally, it was believed that the sand lenses in the claystone layer, due to their discreet nature, might be at virgin pressure (366bar). The top of the claystone layer was anticipated to sit 17m below the 41/2-in. shoe (see Figure 1). Challenges This section discusses the challenges that were encountered in the design and execution of deepening the well. These challenges are divided into two categories, namely technical and non-technical challenges. Technical challenges Described below are the technical challenges that were realized during the planning phase of deepening the targeted well.Shale Stability One of the main technical challenges was to maintain shale stability while deepening. Hence, since the shale potentially contains virgin pressured sandlenses, an on-balance situation had to be maintained in the shale during the entire deepening process. However, this requirement increased the chance of fracturing the upper reservoir, because depletion had reduced its formation strength significantly. This fracturing can lead to severe losses, which in itself can cause an underbalance (and thus unstable) situation in the underlying shale. Additionally since the well had been sidetracked 15 years previously, it had not been possible to kill it successfully. Therefore, preventing severe losses in the upper reservoir was identified as a major challenge.

A review of lost circulation plans, contingencies, recaps, and methods used to primarily prevent losses in the upper-hole sections drilled in the offshore region of the Arabian Gulf was compiled in an effort to ascertain which lost circulation treatments and/or combinations were historically effective or ineffective for regaining circulation especially after total losses, whereby total planned depth was achieved with little to nil non-productive time (NPT) as related to drilling fluids. This evaluation highlighted numerous inconsistencies and excessive time committed to combating losses whereby the critical path was marginalized. While these wells comprised sole objectives, their upper-hole sections were drilled through known troublesome formations often with the same result. It was surmised that the type of lost circulation material (LCM), combinations of LCM, and frequency of use contributed little to no benefit in particular circumstances. Subsequently, this review was undertaken to ascertain if time could be saved with more prudent utilization and/or tactics when utilizing LCM to combat losses. A well-known application of LCM is its usage as background solids to mitigate fluid loss in troublesome wellbore sections primarily due to the relatively inexpensive cost, availability, ease of use, and compatibility with the drilling fluid. LCM are supplied in a myriad of sizes, types, textures, and applied in varying concentrations and combinations. This review details numerous LCM types and combinations in addition to various pills. While attempts were successful in stopping losses in the upper-hole sections, success was sometimes temporary as subsequent drilling operations would, in some cases, realize losses greater than the established trigger rate. The ensuing discussion includes a synopsis of challenging vugular and/or fractured carbonate formations in the UAE and Copper Ridge Formation in the US, a review of common and some uncommon LCM, the field results, and finally, lessons learned and strategies are propositioned. The selected LCM are contrasted with their application in formations of the upper-hole sections versus various loss scenarios and results.

Offshore wind (OSW) energy is a renewable source with strong prospects of development that may decisively contribute towards energy independence. Offshore wind is, however, not yet ubiquitously cost competitive, and frequently requires support schemes to finance its extensive capital requirements. Therefore, cost reduction strategies are necessary for the future development of offshore wind technologies. Even if structural health monitoring (SHM) systems are currently applied for the inspection of critical mechanical structures, they have not been the focus of research from offshore wind stakeholders. The main goal of this study is to evaluate the viability of SHM systems on the support structures of bottom-fixed offshore wind (BFOSW), alongside the impact of implementing these systems on life-cycle. Economic models are used to estimate the impact of implementing these systems, explained using a case-study of the Kaskasi farm in the German North Sea. General results indicate that installing SHM systems on the support structures of offshore wind can shift the maintenance strategies from preventive to predictive, allowing the intervals between inspections to be increased without a reduction on equipment availability. The greatest benefit is related with the possibility of extending the operational life of the farm.