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Holm H.,Shtokman Development AG | Saha P.,Shtokman Development AG | Suleymanov V.,Gazprom | Vanvik T.,SPT Group | Hoyer N.,SPT Group
BHR Group - 15th International Conference on Multiphase Production Technology | Year: 2011

In every oil and gas field development projects, especially when moving into deep water and/or long tieback distances in harsh environments, flow assurance is of crucial importance in order to define a robust, reliable concept which will ensure security of supply during the whole production phase. There are, however, several parameters which affect the flow assurance. The value of these parameters usually is associated with uncertainty, especially in the early phase of the project, as in the concept definition/concept selection phase, and this will inevitably bring uncertainty into the flow assurance analysis. Understanding the level of uncertainty and impact on production performance is the key to making sound technical decisions. An important aspect when moving to ultra long distances is that the effect of small relative uncertainties scaled with 500 km may potentially accumulate to large absolute errors. This paper, which is the first out of two papers in serie /2/ describe a method which has been developed by Shtokman Development AG together with SPT Group in order to facilitate a systematic way of analysing the risk picture, and to identify the major risk contributors in a general flow assurance project. The work and the approach presented is a continuation and improvement of the approach presented in /1/. Application of the method on the ultra long 550 km two-phase flow trunkline from the Shtokman Field to shore is illustrated. © BHR Group 2011.


Hissong D.W.,ExxonMobil | Pomeroy J.,ExxonMobil | Norris H.L.,SPT Group
Journal of Loss Prevention in the Process Industries | Year: 2014

For releases of hydrocarbons from a subsea pipeline, riser, or production facility, the shape of the plume rising through the water must be predicted prior to any assessment of gas dispersion, liquid pools, or fire above the water surface. The location and size of the plume at the water surface are key parameters for subsequent consequence modeling. A mechanistic model has been developed to predict the plume trajectory and size, based on mass and momentum balances and an empirical water entrainment ratio from the literature. With suitable physical property values available, the model is applicable to releases of gas and/or liquid hydrocarbons, predicting the vaporization and vapor expansion due to decreasing hydrostatic pressure as the plume rises through the water. Some validation of the model was obtained with 16 tests in a small-scale transparent tank. The data cover a wide range of flow rates, including both choked and unchoked flow. The predicted and measured trajectories (centerline displacement) agreed reasonably well. Predictions of the model are presented for three fluids. The model is valuable for assessing the consequences of underwater hydrocarbon releases, providing input for subsequent modeling of gas dispersion or liquid pools and pool fires. © 2013 Elsevier Ltd.


Kumar L.,Norwegian University of Science and Technology | Lawrence C.,Institute for Energy Technology of Norway | Lawrence C.,SPT Group | Sjoblom J.,Norwegian University of Science and Technology
RSC Advances | Year: 2014

Pressure propagation in the soft gels is commonly considered either in terms of acoustic waves or gel degradation. However, in a complete description, acoustic, viscous and gel degradation effects should all be considered simultaneously. Here a creep model is discussed with a suitable time scale. The model predicts a specific mechanism of pressure propagation, indicating that gel behaves like a creeping fluid rather than a fluid shearing only above a critical yield stress. The characteristics of pressure propagation can be used to distinguish between creeping and yield stress fluid. The presented results provide a new physical interpretation of recent experimental data. It is also shown that heterogeneity in the gel can cause center-core cohesive failure, as opposed to the near-wall failure which occurs in homogeneous gels. © 2014 the Partner Organisations.


Shi H.,British Petroleum | Norris L.,SPT Group | Berger R.,Manatee Inc.
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2011

A subsea single line tie back in the deepwater of the Gulf of Mexico was recently started up. In order to validate the three-phase transient models used in the studies of the field operations, simulations of the activities actually performed in the initial startup were conducted. Comparisons between simulated and actual start-up operations also serve to improve multiphase flow modeling capabilities for future field design and operations. Formation drawdown, Production Index (PI), arrival pressure, and dead oil circulation rate were all constrained to track actual values during the initial startup. The impact of using different fluid properties was also investigated. In addition, dead oil circulation was simulated by several options to determine which method best matches the field data. The simulated values of liquid flow rates, pressures and temperatures were found to be in reasonable agreement with the data. The slugging event experienced by the field was also captured by the simulation. Comparisons between the simulations and field data served to identify both the strengths and weaknesses of the simulator applied to field operations. Copyright 2011, Society of Petroleum Engineers.


Barroeta R.G.,SPT Group | Thompson L.G.,University of Tulsa
Society of Petroleum Engineers - Trinidad and Tobago Energy Resources Conference 2010, SPE TT 2010 | Year: 2010

In order to demonstrate the importance of using observed pressure data for history matching an early-stage waterflooding process, a novel workflow for experimental design, assisted history matching and probabilistic analysis, was applied to analyze laboratory displacement test measurements. In order to achieve matches between experimental and model data, an evolutionary global optimization technique was used and three different strategies were investigated: matching pressure data only, matching production data only and matching both pressure and production data. For the purpose of generating model displacement data, a one dimensional, two-phase simulator was run. Tornado plots on the matched data reflect that calculated model pressure values appear to be more sensitive to changes in the dynamic calibration parameters (uncertainty parameters) than calculated cumulative fluid values. This implies that use of the pressure drop information enhances the ease with which acceptable history matches can be obtained. Additionally, the results obtained while history matching pressure only were better than those from matching volumetric data only. The results were validated by crosschecking the probabilistic forecasting with real postmortem observed values and by comparing calibrated uncertainty parameters with core petrophysical properties (laboratory analysis). © 2009, Society of Petroleum Engineers.


Yusuf R.,SPT Group | Veeken K.,Royal Dutch Shell | Hu B.,SPT Group
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2013

Reservoir pressure depletion in gas reservoirs causes gas flow reduction with time and eventually leads to liquid loading as the gas flow up the well can no longer efficiently lift the associated liquids to surface. Liquid loading has a detrimental impact on production and a suitable deliquification method is required to continue production and maximize recovery. A dowhhole pump is one such deliquification measure where the pump sits at the bottom of the producing interval and evacuates the accumulated liquids up an insert (coiled tubing) string. It is important to assess beforehand whether the pump will effectively remove the liquids and hence deliver sufficient business value. A transient multiphase simulator has been used to simulate the gas well liquid loading process in a candidate well completed with 5.5″ tubing, followed by the deliquification process triggered by a downhole pump installed 20 m above the bottom of the producing interval on a 1.5″ coiled tubing. Simulations have been conducted for seven different liquid pump rates, three reservoir pressures and two water-to-gas ratios to assess the effectiveness of the pump under different operating conditions and to arrive at the optimum pump size and operation methodology. Simulations indicate that the downhole pump is capable of deliquifying the well and restoring production. However, for a given pump capacity and reservoir pressure, the surface gas production may either oscillate or settle at a steady state value. Oscillations occur when the pump capacity is too high and causes gas ingress into the pump, which introduces partial albeit temporary liquid loading of the wellbore. Continuous steady state gas production occurs when the pump capacity is not too high and an equilibrium situation is reached between the liquid being pumped out and the liquid being produced. The optimum pump rate is controlled by the effectiveness of the downhole separation between the gas and liquid phases and will minimize oscillating ingress of gas into the pump. This study emphasizes the role of transient simulations in predicting the effectiveness of a deliquification measure before embarking on field deployment. The simulations provide valuable insight into flow and pressure transients inside the wellbore during a gas well deliquification using a downhole pump. The information retrieved from the transient simulations is used to decide the optimum pump capacity and operation guidelines. To the best of authors' knowledge, this is the first time that a transient simulation of a downhole pump for gas well deliquification is presented in open literature. Copyright 2013, Society of Petroleum Engineers.


Zubarev D.I.,SPT Group
JPT, Journal of Petroleum Technology | Year: 2010

A comparative study was made of proxy-modeling methods (also known as surrogate modeling or metamodeling) as a computationally inexpensive alternative to full numerical simulation in assisted history matching, production optimization, and forecasting. The study demonstrated the solutionspace complexity for different simulation models and the applicability of the proxy models to mimic it. Focus was given to practical aspects of model construction and to limitations of which engineers should be aware.


Norris III H.L.,SPT Group
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2012

Due to its limited drainage radius, the sand face pressure in a hydraulically fractured, horizontal shale oil well will fall rapidly with cumulative production. Once the sand face pressure falls below the bubble point, flow instabilities will increase dramatically. The onset of instability can be predicted using a transient multiphase simulator such as OLGA1, and techniques to minimize instabilities can be quantitatively investigated through simulation. This paper describes flow instabilities in a typical horizontal shale oil well and demonstrates both causes and remedies for fluctuating production rates in the intermediate and latter stages of well life. Through the suppression of production instability, the ultimate recovery of reserves may be significantly increased. Copyright 2012, Society of Petroleum Engineers.


Transient multiphase modeling system OLGA is used by oil&gas companies worldwide to provide flow assurance and production shut-in time reduction. Traditionally flow dynamic modeling is used to optimize pipeline hydraulic diameter and equipment allocation, simulate liquid loading for various operation scenarios, wax and hydrates.


Martinez-Ortiz V.,SPT Group
SPE Latin American and Caribbean Petroleum Engineering Conference Proceedings | Year: 2012

In this paper a methodology based in multiphase dynamic simulation to size gas-condensate pipelines is presented. This method considers minimum, medium and maximum forecasted field flowrates. Sizing the pipeline considering only the maximum flowrate can result in oversizing the pipeline diameter. An oversized pipeline can cause operational problems when the field's production declines. The multiphase dynamic simulation allows evaluating the flow stability for minimum and medium forecasted flowrates, where the steady state condition may not be defined. In this paper, this methodology was applied to size a pipeline in South America's gas condensate fields. Previously, these pipelines were oversized using only steady-state tools. Copyright 2012, Society of Petroleum Engineers.

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