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PurposeAn abundance of literature suggests that organisations adopting a cooperative approach achieve greater rewards than those that act in opposition or isolation. An emerging body of work also highlights the multiple actors involved in servitization. Despite this, in some contexts the benefits of servitization are not apparent. This paper examines business relationships in the oil industry and how they affect levels of servitization.Design/methodology/approachA mixed method study employing qualitative and quantitative methods was used to fully explore the context. In the quantitative phase, 48 oil industry specialists responded to a scenario based on game theory. This aimed to determine if the relationships between their respective organisations are cooperative or adversarial. Abduction drove a second qualitative phase. This consisted of a series of semi-structured interviews used to explore the servitization level and influence of servitization on relationships and vice versa.FindingsThe statistical results suggest that all parties used adversarial strategies despite the publicised intent to work cooperatively. The interviews suggested that increasing (decreasing) servitization could increase (decrease) cooperation and, in turn, value co-creation but revealed nuances to this effect. It also adds to our understanding of the darker side of servitization by illustrating the impact of mimetic isomorphism.Originality/valueThe findings add to understanding of the complex dynamics around servitization by showing that it is only at advanced levels of servitization that cooperative behaviour is observed, and base and intermediate levels result in non-cooperative behaviour and thus illustrate the importance of adopting a multi-actor lens to explore servitization.

A Major Operating Company in UAE planned and drilled a challenging 6 inch horizontal drain after crossing twenty-seven formation sub-layers. The heterogeneity of pore pressure varied from equivalent mud weights as high as 10.6 ppg to as low as 7.1 ppg across the exposed reservoirs. Control of the equivalent circulating density (ECD) values to safely drill across these multi-reservoir sections and diverse reservoir pressures was one of the top challenges on this well, as the fracture gradients (FG) ranged from 13.5 ppg across the competent reservoirs to as low as 11ppg across the fractured reservoir section. The offset well data review show that 4 out of 6 wells encountered moderate, severe and total losses with mud weight (MW) ranging from 11 ppg to 11.3 ppg, which were cured by using heavy LCM treatments and in some cases, after several failed attempts to cure losses, cement plugs were used. Historically, the average time spent curing total losses in these wells varied from 2-3.5 weeks causing well cost increments as consequence of this non-productive time. All of the above, without mentioning the extra efforts, resources and risks were faced due to well control and stuck pipe events which occurred on those wells. Engineering and Operation teams worked together to engineer a solution to drill this well in one run while safely maintaining the well under control and managing the losses. The Bottom Hole Assembly (BHA) was designed to withstand the well challenges including multiple contingency options. These options allowed:Improving hole quality while tripping using a special type of eccentric reamer stabilizer.Pumping various LCM concentration scenarios through a multi-cycle circulation valve. In addition, a special type of float valve was placed on the top of the BHA as barrier, stopping back flow under surface backpressure or kick scenarios.Optimizing mud weight by using formation pressure while drilling (FPWD) and monitoring both equivalent circulating density ECD and equivalent static density (ESD) by pressure while drilling tools. The drilling fluid was loaded with non-damaging loss circulation material without compromising the MWD/LWD limits. Additionally, the mud rheology was carefully selected and monitored to achieve the desired ECD. On surface, a managed pressure while drilling system was deployed to give control on reservoir pressures. In instances of influx, MPD allows to early detect any kick and controlled by surface back pressure without requiring shut in for applying standard well control techniques. Keeping the well under control by surface back pressure (SBP) during connections time (flow–off). Additionally, MPD also enables the contingency of applying pressurized mud capping in case of unable to control the losses. As decision point, a loss management plan was prepared and implemented. Also, a dynamic formation integrity test was planned and performed to calibrate the fracture gradient across the loss zones. The problematic zone was successfully drilled with one BHA in under six days (5.73 days). The estimated savings for the company were 8 days, which equates to ±1MMUS$ after including the MPD cost which increased the well cost by 200MUS$. To further complement the outright savings, the engineered solution managed to safely stave off operational complications as well as incurring the related complexities and non-productive time (NPT) as recorded on the offset wells. Additionally, well was successfully landed and geo-steered across the target formation and 4½ in liner was run and cemented off-bottom avoiding the need to develop a slot recovery scope on this well with an extra duration of +/-35 days. The engineered solution provided a high level of preparation and contingencies within the BHA, Managed Pressure Drilling Equipment, real time monitoring, mud and cement formulation. The applied techniques allowed the operating company to successfully execute this challenge well within the proposed time and budget.

For several decades, completion design has been performed by the Field Development (FD) Team of several offshore fields in Abu Dhabi and installed with minimal Completion Engineering Team contribution. The demand of lower completion requirement has being increased to maximize well portfolio and enhance well life. The completion design is becoming more challenging and import for key to success. Since a companywide re-organisation occurred a dedicated Completion Engineering Department has been formed to develop a plan to standardise & optimise completions in order to reduce phase duration and NPT. A plan was approved that involved the hiring of a complete engineering department with expertise in many different types of completion and workover operations from all over the globe. This engineering team was brought together from other oil companies and service providers, and tasked with reviewing all current and future completion designs, operations procedures and completion equipment. This was done in order to identify suitability and gaps that were the cause of well construction NPT and identify processes that could be used to reduce or eliminate possible future Well Integrity problems. When the new organisation was formed completion phase NPT reached over 20%, however three month after the NPT had dropped to 11.1%. Within six months of the engineering team starting to be formed, completion phase duration has reduced by 20% and NPT has reduced by almost 50%. These results have been achieved with a concerted effort to maximize understanding of the equipment available to be deployed and develop standardized completion designs that meet the functional requirements of the Field Development Department. As the department has grown and moves forward, a greater involvement in the development of documents such as but not limited to: scope of work and technical requirements for procurement; further deepens the engineering-centric approach that will continue reducing completion phase duration contributing to the operator strategic goals. This paper will show how the newly formed engineering team has managed a complex change from a previous organisation to a new one. Whilst the previous completion design and execution methodology was seen to be successful in other operating companies, the successful engineering-centric approach has been proven within other national operator offshore concessions to reduce phase duration and NPT.

Purpose This paper focusses on the darker side of the dynamics of servitization by exploring the tensions and territoriality that emerge between manufacturers and customers during the servitization process in the oil industry. Design/methodology/approach The Delphi method is used to explore the perspectives of three management tiers in oil organisations and the manufacturers who work with them. The views of these managers were synthesized over three iterations: semi-structured interviews, a questionnaire and resolution/explanation, where consensus was not obtained. Findings The findings of the study highlight perceptions of change, resulting tensions and territoriality and the impact of management commitment, resources and strategy. They reveal significant differences between customers and their suppliers and different management levels and highlight territorial behaviour and the negative impact this has on buyer supplier relationships during the implementation of servitization. Research limitations/implications Further research is required to explore why there is a variation in understanding and commitment at different managerial levels and the causes of tensions and territoriality. Practical implications Servitization is not a “quick fix” and management support is essential. A fundamental element of this planning is to anticipate and plan for tensions and territoriality caused by the disruption servitization creates. Originality/value The research provides empirical evidence of tensions and territoriality relating to servitization that potentially can damage supplier–buyer relationships and suggest that there is a darker side to servitization. It also shows that differences in strategic intent across organizations and between different managerial layers impedes to servitization efforts.