This paper discusses further the application of Blast Furnace Slag (BFS) in the Cementing of oil and gas wells, with particular emphasis being placed on the suitability of BFS for offshore operations in the North Sea. The paper outlines the chemical reactions which occur during curing of BFS and discusses effects of different BFS sources and testing requirements. The application of BFS as a drilling fluid additive to improve Cement bonding by solidification of the filter cake is discussed with respect to the effects of BFS on drilling fluid rheology and fluid loss. BFS is found suitable for low volume operations such as plug cementing, however wider use BFS is seen to be limited by logistics and occupational safety aspects for offshore North Sea applications. The environmental benefits to be gained by use of BFS is limited. Introduction As long as primary cementing operations have been an applied practice within oil field drilling and completion, the development of an effective Mud-to-Cement (MTC) system has been a goal for research. Several methods using Portland cement in MTC systems have been discussed. Wilson et al. applied a copolymer dispersant with an acceptable performance both in (he mud and in the cement slurry. Their MTC system has been applied in a few field trials. In these applications the wells were drilled with chrome lignosulfonate muds or PHPA polymer muds. The take-off of the MTC technology came in 1991 when Hale and Cowan presented their method using Blast Furnace Slag (BFS) as the cementitious material iii the development of a MTC system. They found that BFS exhibited only low impact on mud properties. Therefore BFS could be added to solidify the mud. Another important point is that BFS could be added to the drilling fluid while drilling to ensure that the mud filter cake contains a cementitious material. The application of BFS in cementitious systems was at this time not at all new. BFS had been applied in construction cements for more than a century. It had also been applied as an additive to Portland cements (PC) to limit the heat evolution in the hardening of fresh concretes. In well cementing BFS has been applied for more than two decades in regions where BFS is more readily available. In this case BFS has often been applied to cementing high temperature well sections. According to Shandin, roughly 50,000 tons of BFS per year has been delivered from an iron plant in Konstantinov in the eastern Ukraine for the purpose of well cementing. This BFS has mainly been used for cementing wells in Azerbaidjan and in the northern Caucasian regions. Hale and Cowans's group of researchers continued to promote BFS MTC in a following series of articles. The oil industry were, in the middle of 1993, very optimistic regarding the application of BFS MTC Later that year, Schlemmer et al. gave some technical details about BFS MTC. They found, however, that a PC MTC system is more suitable when the MTC is formulated on the basis of brine muds. P. 143^

When used for running sand control screens, low-solids, oil-based completion fluids (LSOBCF) maintain reservoir wellbore stability and integrity while minimizing the potential risks of losses, screen plugging, completion damage, and productivity impairment. Until now, using LSOBCF as a screen running fluid (SRF) has been limited by fluid density. The design, qualification, and first deployment of an LSOBCF that incorporates a newly developed, high-density brine as the internal phase to extend the density limit is discussed. The following parameters were examined as part of the preliminary qualification: rheology performance, long-term stability, fluid loss (filter-cake repair capability), reservoir fluid and drill-in fluid (RDIF) compatibility tests, emulsion breaking test, production screen test (PST) on 275 µm screen, crystallization temperature [true crystallization temperature (TCT) and pressurized crystallization temperature (PCT)], and corrosion rate. The fluid was then tested for formation and completion damage performance, where the high-density, brine-based LSOBCF exhibited minimally damaging behavior in the core-flow tests. As a result of the positive observations made during these wide-ranging laboratory tests, this new high density-based brine was deemed as a good candidate in an LSOBCF for high-density SRF applications. Viable LSOBCF with densities up to 1.50 SG have been designed. This paper details the design and field application of a 1.45 SG LSOBCF. Calcium bromide (CaBr2) brine is commonly used during the discontinuous phase for LSOBCF applications that require fluid densities up to 1.38 SG. For higher density requirements, LSOBCF use a cesium formate brine as a discontinuous phase. Using the new developed brine in the discontinuous phase provides viable LSOBCF up to 1.50 SG. The base brine has a good environmental rating, is pH neutral, and provides improved safety during low-temperature/high-pressure conditions. As a standalone fluid, the new brine can achieve densities up to 1.80 SG, with acceptable TCT and PCT values for North Sea applications without using zinc or formate-based brines. After laboratory qualification, the final fluid formulation was deployed on a dual lateral oil producer well with 9.5 in. horizontal reservoir section lengths of 2315 and 1696 m. After drilling the sections using an engineered low equivalent circulating density (ECD) oil-based RDIF (OB RDIF), each section was sequentially displaced to 1.45 SG LSOBCF. The lower completion, consisting of 5.5 in. screens equipped with autonomous inflow control devices (AICD) and swellable packers, was successfully run to bottom without significant issues. The field application demonstrated evident operational efficiency gains. The positive pre-deployment formation response test (FRT) results have been verified by well productivity data. The process to qualify the brine for first-use application in LSOBCF is described, and laboratory testing (including FRT), mixing and logistical considerations, field execution, and well productivity are discussed.

For the Johan Castberg field development project, injector wells are important for achieving high production and overall high recovery factors. Injectivity has become more important due to limitations in injection pressures and required control of fracture growth. Securing injectivity has been identified as one of the project’s main risks, making drill-in fluid and breaker fluid system qualification a vital parameter for success. Operational procedures and completion design also affect the effectiveness of breaker fluid placement and, thus, the overall injectivity of the well. In this paper, we present a cross-disciplinary systematic approach for the reservoir drill-in fluid and breaker fluid qualification to ensure injectivity in these wells. Two wells were selected for covering the expected pressure and temperature range of the field in an environmentally sensitive area. Two independent fluid systems were designed, where the bridging material consisted of either sized salt particles or calcium carbonate particles. The open hole completion design has been optimized for an effective breaker fluid placement, using a modified gravel pack system with a wash pipe. The displacement sequence has been optimized for effective deployment. An extensive laboratory test matrix for both the reservoir drilling fluid (RDF) and breaker fluid system was established, including thorough analysis of the interaction between the deposited filter cake and the breaker fluid system. The RDF and breaker fluid formulation optimization was performed whilst keeping in mind the operational requirements and the well’s future injectivity The presented results show successful qualification of two independent fluid and breaker fluid systems where filter cake breakthrough is achieved within the desired time frame. The fluid systems in combination with the lower completion design and operational procedures ensure maximal reservoir exposure of the breaker fluid solution and enable rapid deterioration of the filter cake.

For decades, wells targeting the Rotliegend reservoir in the Southern North Sea Basin have been drilled using conventional water-based mud (WBM) in the top hole section and oil-based mud (OBM) systems throughout the remaining sections of the well. The standard well design generated high waste disposal costs onshore and offshore, particularly with regard to OBM waste. This study evaluates alternative fluid systems to help reduce disposal costs for the operator. As part of the operator's environmental improvement strategy, the operator and fluids provider team identified potentially significant waste disposal cost savings for an onshore trial. Using a WBM system for drilling top holes as well as through the lower sections could result in cost savings through the reduction of top hole fluid dilution as well as a reduction in waste disposal costs. A high-performance water-based mud (HPWBM) system with similar performance to an OBM system was proposed as part of a trial to demonstrate these potential savings in disposal costs for an onshore well. The field trial was a great success compared to conventional fluid systems and methodologies. The well was drilled 11.6 days ahead of schedule and 20% under the planned budget. The time vs. depth curve was on par with what was expected when drilling with an OBM system. The HPWBM system created a saving of >5% of the total well cost and it was 16% less expensive than conventional fluid systems. A further saving of 2.5% of the total well cost was identified for future onshore/offshore applications of the HPWBM system. It was also theorized that a further reduction in waste disposal costs could be realised in offshore operations. The field trial was based on a basic onshore well trajectory as a proof of concept. Upon the success of using HPWBM in the basic well, more challenging onshore as well as offshore applications would be examined which have the potential to double the cost savings generated. This novel approach of using an environmentally acceptable HPWBM system in the Southern North Sea Basin can offer significant cost saving opportunities with regard to waste management for both onshore and offshore wells compared to conventional WBM and OBM systems.

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