Abstracts S101respectively. Of those individuals with HIDA scans ordered, only 18.5% were deemed appropriate (20.0% for bile leak, 12.7% for acute cholecystitis, and 22.0% for biliary colic). When scans were ordered inappropriately, subsequent management changes occurred in only 8.15% of these patients. Conclusion: Th e vast majority of inpatient HIDA scans are inappropriately ordered, adding to cost of care while adding no clinical benefi t. In patients with biliary tract signs and symptoms, following consensus guidelines can help the clinician decide on the most appropriate imaging work-up and avoid unnecessary testing.

Millions of dollars are spent across the oil and gas industry on data gathering activities with a view to reducing subsurface uncertainties towards optimizing reservoir development and management. However, suboptimal attention is often paid to assessing the value of the information (VoI) during data acquisition requirement planning and before requesting for such information. The capital intensiveness of the industry and emerging low oil price regime has necessitated scrutiny on every dollar spent on data gathering in the current business terrain. The application of the VoI concept in the oil & gas industry provides a predictive, analytic and quantitative framework for decisions and justifications for data gathering activities including but not limited to log data acquisition; downhole fluid sampling; subsurface diagnostic tests; core data acquisition; appraisal drilling and seismic acquisitions. Value of Information in simple terms is described as the amount a decision maker should be willing to pay for a piece of information. It is evaluated as the difference between the future value of a project given the availability of particular information versus its value without it. This paper demonstrates the methodology and application of VoI analysis to support a key decision on whether or not to drill an appraisal leg of a well to test for fluid contact and possible presence of an oil rim in a reservoir prior to initial gas development. The major uncertainty in this study is the evaluation of the hydrocarbon extent in a gas reservoir with a gas-down-to (GDT). To evaluate the options, a VoI analysis was carried out by integrating results of different data sources; well log data; formation pressures; seismic data and analogue information. Integration of the different data was used to arrive at different subsurface realizations which fed into 3D static and dynamic simulation models. The modeling result for the different scenarios was used as input for economics in the VoI analysis. Using the multiscenario analysis, the range of oil rim thickness proved to be non-commercial and the VoI analysis showed that drilling an appraisal will result in a negative value of appraisal giving the estimated VoI and cost of drilling an appraisal well. The analysis has led to significant cost saving of about $8million which is the appraisal cost of an earlier planned appraisal/development well. The analysis also helped to challenge the pre-existing appraisal paradigm and provided a robust basis for a commercial decision without compromising on regulator standards and industry best practices.

Smart well technology allows production acceleration from multiple completions and value realization from otherwise marginal reservoirs. Critical to the success of a smart well completion targeting more than one reservoir is the proper design selection and reservoir isolation to prevent cross flow. This case study describes the selection of a suitable gas well design from different available options, the considerations made in the design selection which incorporated the different completion components, one of the components being the feed-through swell packers which is its first use in the company, to achieve reservoir isolation. The paper also describes the execution of the selected completion design in one of the cases, as well as the testing of the well to verify reservoir isolation, and confirm the effectiveness of the feed-through swell packer. The selected completion design was cost effective, reduced operational / deployment risks (compared to other isolation options) and had no adverse impact on well productivity of the wells. It also achieved the objective of accelerating the recovery of a combined volume of 221 Bscf of gas from marginal gas reservoirs in a field.

Well integrity is a key focus area in any oil and gas development. There have been several cases of well integrity issues which have resulted in scenarios of blowout, loss of lives, assets, and reputation, including costs spent for clean-up and environmental remediation, amongst others. These and more have made the energy industry put a keen focus to making sure all hydrocarbon production and processing facilities are integral, with newer technologies still being developed to aid the diagnosis of well integrity problems. Well integrity considerations cut across the entire life cycle of the well, from well conceptualization/planning through to drilling, completion, production and abandonment. This case study presents a high-pressure, high temperature gas well with sustained annulus pressure in the early production phase of the well. Well X is a gas well completed in an elevated pressure and temperature reservoir on a land terrain. The reservoir is about 13000ftss deep, with a temperature of 219°F and a reservoir pressure of 9300psi. The well was completed, cleaned up and brought to production about a year ago and annular pressures were observed. This paper details the different approaches used in diagnosing the sustained annular pressures – separating thermal effect from sustained pressure due to leak. It shows the different scenarios of leak paths identified and how these were streamlined. The paper also highlights the integration of data acquired during the investigation. Some of the data acquired include well annuli pressures, high precision temperature logs, spectral noise logs and electromagnetic corrosion logs.

The paper seeks to find the optimum solution on how to develop some portion of a unitized field. The case study involves two fields straddling across four oil mining leases (OMLs), in Niger Delta, Nigeria. Each field were operated independently by JV-A and JV-B until mid-2016 when the operatorship of the straddling reservoirs (SRs) in the unit was granted to JV-B by the regulators, as it is a law in Nigeria that all straddling reservoirs should be developed as a unit under a single operator. The decision on whether JV-A should grant JV-B the right to also operate the non-straddling reservoirs (NSRs) in the unit will depend on the amount of tariff imposed. JV-A will be required to pay hydrocarbon transportation and processing tariffs if it flows its share of the produced hydrocarbon through JV-B's existing facility. The exact amount of tariff is unknown and will be negotiated. Additionally, four feasible evacuation routes exist and will be considered for this evaluation to decide the most profitable and capital efficient investment option. The result shows that the opportunity is very sensitive to hydrocarbon handling tariff; necessitating JV-A choice of evacuation route. In addition, the paper demonstrates how using appropriate project framing and considerations of who will operate the JV-A's non-straddling reservoirs, relied heavily on different hydrocarbon transportation and processing tariffs. It is hoped that this paper having highlighted the importance of tariff charges and the role of proper framing on decision quality will encourage decision makers to adopt this approach during decision analysis and ultimately improve the quality of investment decisions particularly for Non-operated venture (NOV) projects.