The Alba field in the central North Sea is an unconsolidated sandstone reservoir with an average permeability of around three darcies. Maximising productivity and extending completion life has been an evolving process throughout the life of this field. Recent practice is to drill the horizontal reservoir section using a water-based drill-in fluid (DIF) and complete with a circulating open-hole gravel pack (OHGP). One current option employs an oil-based DIF prior to gravel packing in brine. Both of these procedures have allowed higher off-take rates from these wells than previous completion practices. New advances in the nature of delayed stimulation chemicals and the introduction of more effective additives (generating acid in situ downhole) made it of considerable interest to determine whether productivity could be further enhanced. One major obstacle to overcome was the uncertainty associated with the placement and uniform distribution of the stimulation treatment in a horizontal well, allowing the entire filter cake to be contacted and broken down successfully. This paper describes how the deployment problems were successfully circumvented. A dual density treatment was employed in which both the upper and lower zones of the horizontal well-bore were targeted so that the filter cake on both the upper and lower surface in the hole would be contacted and attacked. Evidence will be provided indicating the placement resulted in an enhanced productivity index compared to conventional, non-stimulated completions. The new stimulation treatment was effective in wells drilled with either a water-based DIF or an oil-based DIF. Introduction The history of the development of the Alba field over theperiod from its inception until 2002 has been reported in previous publications.1,2 This paper reports recent developments. The Alba oil field located in block 16/26 of the UK sector of the North Sea comprises an Eocene sandstone formation that is thin, highly porous, highly permeable, very unconsolidated and overlain by a bed of impermeable, highly reactive shale. The nature of the reservoir dictated that development would be best achieved by open hole completions and highly deviated or horizontal reservoir sections with the productive interval being sited near the top of the sand body. The earliest approach was to run screen only completions, initially using synthetic oil-based mud (OBM) as the drill in fluid (DIF), evolving through the same screen arrangements but using a saturated brine/sized sodium chloride based DIF. Both approaches provided excellent drilling properties but there were severe limitations in respect of productivity in the case of those wells drilled with synthetic-based mud (SBM) and screen longevity was a problem for the wells using the sized salt approach.1 Both issues were addressed by adopting a sized carbonate DIF and performing open hole gravel packs (OHGP) on the productive sections. Since these observations on the evolution of the drill-in fluids and completion strategies on the Alba were reported, several other important developments have been made. In apparent contrast to the message provided in the earlier report2 about the robustness of the gravel pack completion philosophy relative to stand alone completions, the appearance of extremely early well failures on a few gravel packed wells have given cause for additional concern. As previously reported, the well failure data indicated that the standalone screen completions had failure rates in the order of 70–90%, with failures typically occurring after one to three years of production. Open hole gravel packed wells, in contrast, at least initially, exhibited prolonged well life. Thirteen open hole gravel packs were successfully completed and on line before any incidence of failure.2 Subsequently, the field has experienced four well failures in a relatively short period of time. One of the wells in question produced for four years before failing but the other three failed after only a few weeks of production.

This paper describes the design and qualification process used to select a reservoir drill-in fluid (RDF) for the Peregrino field offshore Brazil, and the successful application of this fluid. The Peregrino field is located east of Rio de Janeiro in the southwest Campos Basin area. Approximately 2.3 billion barrels of oil are in place in the Peregrino reservoir. The productive sands in this variable reservoir typically exhibit permeabilities between 6 and 15 Darcy, and are unconsolidated with interbedded shales. Peregrino crude oil is heavy (13API) and viscous. The estimated recoverable volume of crude oil is 300 million to 600 million barrels. The selected fluid, a NaCl brine-weighted water-based mud employing KCl and Glycol additions for shale stabilization, was used to drill the first wells at Peregrino. Penetration rates were high and zero non-productive time occurred. To achieve this drilling performance in the high permeability, unconsolidated, heavy oil reservoir, an extensive fluid selection process was performed to optimize the drill in fluid for maximum well productivity. Key test results reviewed in this paper include: Bridging solids optimization, lubrication, shale inhibition, fluids compatibility, filtercake lift off and backflow performance, breaker fluids and formation damage The reservoir sections of the wells were successfully drilled, open-hole-completed with sand screens and gravel packed with 100% efficiency.

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This paper describes the first field application of a high-pressure/high-temperature (HP/HT) organophilic clay-free invert emulsion fluid (OCF IEF) weighted with small-particle-sized (SPS) barite, qualification of which was achieved through extensive laboratory investigations (described elsewhere). The paper describes detailed observations of the fluid performance during first use (i.e., “critical first well application”) on a Statoil-operated HP/HT field in the North Sea. In the well selected for first application, finger-printing was performed so that behaviors of the 1.96-specfic gravity (sg) invert emulsion fluid (IEF) could be examined and recorded before entering the open hole. When in the open hole, observational tests were continued throughout the well. Before and after trips, fluid behavior and properties were monitored and recorded. Additionally, extensive fluid testing was conducted on the rig (rheology, HP/HT fluid loss, particle plugging test [PPT] static sag, and viscometer sag shoe test [VSST]). Before running stand-alone screens (SAS), screen flow-through tests were performed. Extensive tests showed acceptable fluid performance within stringent, defined criteria at all times. When re-initiating circulation on several consecutive connections, pump ramp-up time was gradually reduced. No pressures above drilling equivalent circulating density (ECD) were observed at any time. While drilling, the ECD values were maintained well within the required values. No barite sag was observed on any occasion, even after 90 hours static or during a slow circulation rate test performed to simulate conditions likely to induce dynamic sag. Fluid loss control (PPT) was maintained within specifications through the addition of ground marble. A decrease of approximately 60% in fluid treatments compared to a conventional HP/HT IEF resulted in a reduction in chemical and logistical costs and manual handling. The well was drilled well ahead of plan, resulting in saved rig time. No issues were observed when running screens to total depth (TD) with the IEF. The well was easily brought on production after ∼30 days, with the IEF being produced back to surface, consistent with expectations from the qualification laboratory testing undertaken at Statoil's laboratory facilities. Highly acceptable production rates were achieved, indicating minimal productivity impairment. The efficient drilling of the well, along with being able to complete the well in the same IEF and not displace to brine, as was previously performed, resulted in substantial cost savings compared to other qualified solutions. This successful first application demonstrated that the well could be drilled and completed in the same fluid with an enhanced drilling performance and highly acceptable productivity outcome.

During recent years there has been a significant increase in the use of filter cake removal systems that involve in-situ release of formic or lactic acid during the clean-up stages of the reservoir section, particularly in limestone formations. Furthermore, there have been opportunities to compare the field performance of these relatively small applications of weak, organic acids with significantly larger application volumes of highly concentrated hydrochloric acid (HCl). Surprisingly, some results showed that the smaller volumes of the weaker, organic acids could have equivalent or better performance than that produced by the more traditional HCl-based treatments. In particular this relationship was also observed in cases where the volume of HCl applied had significantly greater power to dissolve limestone than was the case for treatment with the more successful organic acid. It is well known that productivity of wells in carbonate reservoirs is usually greatly improved by treatments designed to remove the filter cake and the low-permeability zone created by the drilling process, but it is not obvious why smaller volumes per foot of weak organic acid should be more effective than larger volumes per foot of stronger and more concentrated mineral acid. It has been observed that the acid precursors which release the in-situ acids are applied to the formation in a neutral condition. The paper discusses the implications of using neutral acid precursors, and laboratory data is presented showing the effects of such treatments on the near-wellbore matrix permeability.