TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFlow assurance is a key priority for the subsea community as it is being challenged to provide answers to the following question: Can we manage the risk of hydrocarbons flow interruptions while optimizing the system performance using current flow assurance practice?Traditionally, flow assurance has focused on evaluating potential production problems associated with produced fluid issue such as waxes, asphaltenes, hydrates and scale. A combination of fluid sampling, laboratory techniques, and predictive modeling are then used for system selection and design of prevention and remediation strategies. These are often based on conservative modeling practices using incomplete or inconsistent data sets. No allowance for continuous monitoring that will provide data needed to recalibrate the system or to change the course of the process over the subsequent years is made. The result is often an overly conservative system design and operating strategy.The paper discusses a more dynamic approach to answering the above question as it explores the integration of the design and surveillance processes. Advances in sampling, analysis and modeling that reduce conservatism in design are reviewed. The role of real-time measurements during production from the reservoir, the wellbore, and the subsea infrastructure, in monitoring and optimization of a system is then discussed. Specific case examples are presented throughout to illustrate these points..

This paper discusses the early evaluation of vertical connectivity with vertical interference tests (VITs) using an advanced multi-probe wireline formation tester in a giant carbonate field in Saudi Arabia. The objective was to determine the vertical permeability of low permeability layers within the reservoir. Early understanding of the vertical connectivity is required to ensure the optimum development for new fields with limited dynamic data. To conduct the evaluation, a multi-probe advanced formation tester was utilized in five key wells around the field to obtain vertical and horizontal permeabilities with several VITs creating pressure pulses at the dual packer, which produce pressure responses monitored at the two observation probes in real time. The vertical connectivity was assessed from the pressure response to the transient generated across stratigraphic layers. Comprehensive interference tests were conducted across all the layers. Advanced nonlinear regression analysis techniques were utilized for pressure transient analysis at test intervals. The results were further confirmed with a fine gridded 3D reservoir simulator. The integration of all vertical permeability results obtained so far indicated a good degree of reservoir vertical connectivity. The VIT results were used as input in the field simulation model improving the accuracy of the vertical permeability in different areas of the reservoir, which in turn supported changes in the well placement strategy to maximize recovery.

The validation of multiphase flowmeters (MPFMs) in a controlled flowloop using live hydrocarbon fluid is examined with emphasis on the impact of measured and modelled fluid properties uncertainty on the loop reference measurements. A customized process model based on data reconciliation with integrated thermodynamics package is built to evaluate the loop reference flowrates and their uncertainties at the multiphase flowmeter test station conditions. The process model accounts for data redundancy and physical constraints to ensure consistency of the reconciled measured and unmeasured variables used in the validation of multiphase flowmeters. The model is applied to a generic set of test points performed in a high pressure (HP) flowloop. The paper discusses the modeling and operational aspects involved in validating the subsea meter's measured flowrates. It also highlights the sensitivity of different inputs and their uncertainties on MPFM performance evaluation. For the first time, the proposed approach enables operators to achieve the reality of subsea operations inside a highly controlled flowloop environment without resorting to overly simplified assumptions and practices. The approach is further validated by applying it to a high-pressure, high-volume, true multiphase flowloop using actual hydrocarbon fluids.

The paper presents a methodology and results of a study to derive the gas-oil ratio (GOR) of oil in situ based on downhole ultrasonic sound speed formation tester measurements. Authors provide several cases as a reference for in-situ fluid acoustic measurement values, and cleanup profiles in various borehole and downhole settings, to illustrate their benefits for formation testing as well as other geoscience applications. Formation tester dynamic fluid measurements of analysis of 47 samples from 25 wells were assessed. Reference GOR measurements were collected from different sources. The relationship between in-situ sound speeds corresponding to reference GOR was assessed and showed strong correlation within the investigated range. To enhance estimation accuracy, another two methods of deriving GOR using fluid slowness, downhole condition parameters, and computed pseudo-density are presented. The assessment of formation tester fluid slowness data showed its consistent association with live oil GOR within the studied range (~20-1,500 scf/bbl). Further increase in GOR showed change in the relationship trend. Several methodologies of GOR estimation are discussed including multiple linear regression using fluid slowness, in-situ pressure, temperature, and linear regression with estimated pseudo-density of a fluid. The multiple regression output showed slightly better match with laboratory data. Results of other data modelling approaches are also discussed. The proposed GOR evaluation methodology is based on acoustic surveys made downhole without phase separation. The results are available at the time of formation testing cleanup and fluid sample capturing stages. The additional benefit of the method is to aid in assuring fluids are maintained in single phase for collection of representative samples.

Six Pakistani crude oils are characterized and their rheological behavior is studied in a standard rotational rheometer. TBP distillation data and density of whole crude oil are used to perform the basic characterization and to obtain the product distribution of the crudes. All the crude oils studied exhibit non-Newtonian behavior under the conditions of experimentation. Various non-Newtonian models such as the power law model, Bingham plastic model, and Herschel-Bulkley model are used to fit the experimental rheological data. The power law model exhibiting pseudoplastic behavior is found extremely satisfactory for the majority of the crude oils.