0

ASME Conference Presenter Attendance Policy and Archival Proceedings

2015;():V010T00A001. doi:10.1115/OMAE2015-NS10.
FREE TO VIEW

This online compilation of papers from the ASME 2015 34th International Conference on Ocean, Offshore and Arctic Engineering (OMAE2015) represents the archival version of the Conference Proceedings. According to ASME’s conference presenter attendance policy, if a paper is not presented at the Conference, the paper will not be published in the official archival Proceedings, which are registered with the Library of Congress and are submitted for abstracting and indexing. The paper also will not be published in The ASME Digital Collection and may not be cited as a published paper.

Commentary by Dr. Valentin Fuster

Petroleum Technology: Drilling Mechanics

2015;():V010T11A001. doi:10.1115/OMAE2015-41058.

Based on the bit-rock interaction laws, a simple nonlinear 2-dofs mass-spring model is developed to analyze the dynamic cutting process with normal ultrasonic vibration excitation. The study presents a single cutter used in Polycrystalline-Diamond-Compact (PDC) drill bits. Using the 4th Runge-Kutta’s algorithm, numerical simulation found that ultrasonic vibration-induced contact deflection and even loss of contact. The contact friction between the rock and wear-flat (wear surface), which relates to the reaction force, is therefore reduced. This will reduce the wear on the cutter and the force needed to cut the rock. This indicates that the average reduction of friction induced by ultrasonic vibration can be explained by decreasing the average normal force on the cutter-rock wear-flat, rather than changing the friction coefficient.

Commentary by Dr. Valentin Fuster
2015;():V010T11A002. doi:10.1115/OMAE2015-41226.

A dynamic bottom hole assembly (BHA) model is built with finite element method (FEM) in this paper. This model is used for evaluation the influence of externally added vibration to the BHA system. With this dynamic model along with a general bit-rock interaction formula, the BHA’s motion in axial and torsional directions are examined. Parametric study is carried out by varying the parameters of the applied vibration force, including the mean value, amplitude, angular frequency, and the location of this force excitation. The simulation results indicate that externally applied vibration force is indeed able to improve drilling performance. In particular, the mean value and amplitude of the applied force have a almost linear relation with ROP and WOB. The stresses distributions along BHA are investigated as well.

Topics: Drilling , Vibration
Commentary by Dr. Valentin Fuster
2015;():V010T11A003. doi:10.1115/OMAE2015-41393.

Current types of axial excitation tool have been shown to produce beneficial results — in terms of load transfer to the bit, general reductions in string friction and reductions in drill dysfunctions — such as stick slip.

The positioning of such tools to achieve optimum benefit is therefore extremely important — in order to maximize the axial excitation to the areas of the string that require a reduction in friction, and also to minimize the axial excitation to the surface and to sensitive string tools (such as MWD) — where damage may occur.

This paper describes a string model that allows the position of axial excitation tools to be assessed — in terms of the string response — both locally and remotely from the tool.

The model breaks the string down in to springs and masses — with 10 nodes in the upper string; and 5 nodes in the BHA. Additional components can also be added to the string — such as shock tools, jars and accelerators — in terms of mass and stiffness.

The equations of motion are used to connect the nodes in terms of differential equations.

The model is Mathcad based, and as a result, executes very quickly — so allowing comparative studies to be carried out with relative ease.

Data input into the model is also achieved quickly.

The speed with which the model can be used lends itself to fine tuning input data.

The model has been compared with and ANSYS spring mass model, and good agreement has been reached.

Additionally, the model allows more than one axial excitation tool to be added to the string — in order to gauge the benefits of such a configuration.

Damping can also be varied at different locations in the string model.

The results from this model have been used to compare with field test data — derived from a string with instrumentation tool located at various points in the string.

The results show that good agreement can be reached between the model and the field test results, however, careful consideration needs to be taken of the damping assumed in the model.

The model can, never the less, be used for comparative studies — i.e. tool location, number of tools and optimum frequencies.

Further work is recommended in comparing model results with field test results — in order to get a better understanding of the effect of damping.

The damping model could be improved in the model presented here, or alternatively, the lessons learned here could be merged into an existing string model.

Topics: String , Modeling , Excitation
Commentary by Dr. Valentin Fuster
2015;():V010T11A004. doi:10.1115/OMAE2015-42227.

Severe drill stem vibrations could leads to excessive damage to the bottom hole assembly causing an increase in nonproductive time. Different drill stem vibrations models are used to predict and avoid resonance regions by optimizing the selection of bottom hole assembly components and operating parameters such as weight on bit, and surface RPM. In addition to avoid the resonance regions, specialized tools have been developed to reduce vibrations. However a complete understanding on how to mitigate vibration and its effect on drilling performance is still lacking. This study investigates the cause of drill stem vibrations, its effect on drilling performance, and the effect of including vibration reductions tools in the bottom hole assembly design in several recent drilled wells in the North Sea.

Vibration damping tools used in this study were able to reduce both lateral and torsional drill stem vibration compared to a well with no vibration damping tool. Torsional drill stem vibrations tend to increase through rich sand zones causing an increase in lateral vibrations. The impact drill stem vibrations have on drilling performance was identified through rate of penetration. As lateral vibration intensity increases, instantaneous rate of penetration decreases.

Commentary by Dr. Valentin Fuster

Petroleum Technology: General Petroleum Technology

2015;():V010T11A005. doi:10.1115/OMAE2015-41141.

In the current study, two-phase flow modeling in oil and gas applications using asymptotic analysis is presented. Examples of two-phase liquid-liquid flow in pipes, two-phase gas-liquid flow in fractures, and two-phase gas-liquid flow in porous media are presented. In the present study, a simple semi-theoretical method for calculating the two-phase frictional pressure gradient in oil and gas applications using asymptotic analysis is presented. The proposed model can be transformed into two-phase frictional multiplier as a function of the Lockhart-Martinelli parameter, X. The advantage of the new model is that it has only one fitting parameter (p). Therefore, calibration of the new model to experimental data is greatly simplified. The new model is able to model the existing multi parameters correlations by fitting the single parameter p. Comparison with experimental data for two-phase frictional multiplier versus the Lockhart-Martinelli parameter (X) is presented.

Commentary by Dr. Valentin Fuster
2015;():V010T11A006. doi:10.1115/OMAE2015-41171.

In this article, three different methods for modeling of twophase frictional pressure gradient in circular pipes are presented. They are effective property models for homogeneous two-phase flows, an asymptotic modeling approach for separated two-phase flow, and bounds on two-phase frictional pressure gradient. In the first method, new definitions for two-phase viscosity are proposed using a one-dimensional transport analogy between thermal conductivity of porous media and viscosity in two-phase flow. These new definitions can be used to compute the two-phase frictional pressure gradient using the homogeneous modeling approach. In the second method, a simple semi-theoretical method for calculating two-phase frictional pressure gradient using asymptotic analysis is presented. Two-phase frictional pressure gradient is expressed in terms of the asymptotic single-phase frictional pressure gradients for liquid and gas flowing alone. In the final method, simple rules are developed for obtaining rational bounds for two-phase frictional pressure gradient in circular pipes. In all cases, the proposed modeling approaches are validated using the published experimental data.

Commentary by Dr. Valentin Fuster
2015;():V010T11A007. doi:10.1115/OMAE2015-41218.

Hard rock drilling is facing increasing importance by using geothermal energy as a new energy source. Percussive drilling methods are generally well suited for drilling hard rocks. However, until now there is no drilling tool available on the market that uses percussive drilling methods and can be applied in deep boreholes in combination with common drilling muds. The aim of the DGMK project 733 is to develop a hammer drill which generates the impact energy downhole and works with conventional drilling mud. Seven different drive concepts were developed during the feasibility study. Demonstrators were manufactured for four of the seven drive concepts. The evaluation of the drive concepts showed that two of them have a high potential for the implementation in the field. These two concepts will be developed further to laboratory prototypes and were investigated at a test facility.

Topics: Drilling , Hammers
Commentary by Dr. Valentin Fuster
2015;():V010T11A008. doi:10.1115/OMAE2015-41219.

The costs of drilling in hard rock depend significantly on the available drilling technology. Conventional drill bits are especially adapted to the needs of the oil and gas industry but they are limited for drilling in crystalline formations. The Electric Impulse Technology offers a promising alternative for this purpose. The splitting effect of electrical explosions inside the rock is used to destroy the rock instead of working mechanical against the compressive strength of the rock. In a project funded by the BMWi (project number 0325253) a drill head was developed, which consists of a pulse power source of up to 500 kV and electrodes for a 12 ¼″ borehole. The drill head is designed for downhole pressures up to 1000 bar and temperatures up to 200 °C. A test stand has been implemented at the TU Dresden. Drilling tests under borehole like conditions could be performed. Drilling speeds of 1 m/h could be proven. The follow-up project started in the end of 2014. The drill head will be optimized and the power supply will be designed. The total system will be used in a test well and investigated.

Commentary by Dr. Valentin Fuster
2015;():V010T11A009. doi:10.1115/OMAE2015-41425.

This paper introduces the functionality of a new type of Autodriller software system, which can acquire downhole weight on bit (DWOB) based on surface rig measurement. Field tests are performed, including DWOB measured by downhole measuring tools and the hookload below the top drive using a TTS (Torque and Tension Sub). Three sets of drilling data from three horizontal wells in Western Canada were utilized to verify the models of this new Autodriller system. DWOB comparisons between the model and the measuring tools were carried out. The comparisons indicate a good agreement between the downhole measured DWOB and the new Autodriller predicted values. The difference between the new Autodriller prediction and downhole measured DWOB can be quantified using rooted mean square error (RMSE) or relative error (RE). This paper also analyzes the differences in some sections, and some measures are suggested to potentially reduce these differences. The new Autodriller is a closed loop control system which can automatically in real-time adjust surface weight on bit (SWOB) so that the DWOB is accurate, which will directly improve the performance of drill bits, and decrease the cost of drilling, especially in directional well drilling applications.

Commentary by Dr. Valentin Fuster
2015;():V010T11A010. doi:10.1115/OMAE2015-41426.

The current interest in directional survey calculations is related to the increased number of highly deviated holes drilled from offshore platforms. Positional accuracy is important because, when two wellbores closely approach one another, it is essential to avoid intersection. Also, when a relief well is drilled, it is important to achieve intersection with the wild cat well. Unfortunately, there is no set of calculations that can be used to analytically determine exact bottomhole position relative to the top hole. Therefore, uncertainty with respect to estimating the wellbore position should be determined using directional surveys and the different models being used.

Errors in estimating the target primarily derive from two sources — model errors and measurement errors. Model errors occur in the calculations used to estimate borehole position because of a lack of complete information, which can only be tackled by having an infinite number of survey stations throughout the well path. On the contrary, measurement errors occur in the readings of inclination angle (I), azimuthal angle (A), and the distance between two stations (L). This paper focuses on estimation of measurement error, which is an inherent property of measuring instruments being used for the survey and can be evaluated numerically after making some assumptions necessary for such an analysis. The said analysis would ultimately provide ellipses of uncertainty for the target point based on different survey models.

The study is based on a paper by Walstrom et al. [1], which uses the angle averaging (AA) method for survey calculations. The study is extended for calculating measurement errors in the following models: the radius of curvature (ROC), minimum curvature (MC), and natural curve (NC) methods.

Commentary by Dr. Valentin Fuster
2015;():V010T11A011. doi:10.1115/OMAE2015-41955.

This paper presents the analysis of a hysteresis interior permanent magnet (IPM) motor drive for electric submersible pumps. A hysteresis IPM motor is a self-starting solid rotor hybrid synchronous motor. Its rotor has a cylindrical ring made of composite materials with high degree of hysteresis energy. The rare earth permanent magnets are buried inside the hysteresis ring. A hysteresis IPM motor can self-start without the need of additional position sensors and complex control techniques. It does not have any slip power losses in the rotor at steady state which results in less heat dissipation and low electrical losses. When used in an electric submersible pump (ESP) for oil production, it has the ability to automatically adapt itself to the changes in well conditions. In this paper, a bond graph model of a hysteresis IPM motor ESP drive is used to predict the effect of pump shaft geometry on transient behaviour of the drive during start-up. Simulation results show that the hysteresis IPM motor drive has high efficiency, and is better able to maintain its speed during changes in load. Due to increased efficiency and simplified controller requirements, the hysteresis IPM motor is proposed as a replacement for the standard induction motor currently used for downhole ESPs. This is expected to improve ESP performance and reliability which are critical requirements for use in harsh offshore environments such as Atlantic Canada.

Commentary by Dr. Valentin Fuster
2015;():V010T11A012. doi:10.1115/OMAE2015-42314.

In the current study, an experimental study on two-phase flow at different orientations is carried out at the Fluids Laboratory, Memorial University of Newfoundland (MUN). Three different orientations are used. They are horizontal, vertical and slanted orientation respectively. The experimental unit consists of pipes that are three inches (DN 80) in diameter and are capable of producing many various regimes of gasliquid flows. The experimental unit has sensors to measure the pressure, temperature and volume flow at numerous locations. Experiments are conducted for two-phase flow (bubble and slug flow). The new experimental data can provide valuable insights on the viscous effects with many flow regimes, phase compositions and direction of flow. The results of this research provide valuable new experimental data on two-phase flow characteristics for many flow regimes that can improve the safety and efficiency of wellstream flows.

Topics: Two-phase flow
Commentary by Dr. Valentin Fuster
2015;():V010T11A013. doi:10.1115/OMAE2015-42385.

In this study, a dynamic model of a Mobile Offshore Drilling Unit (MODU) is described that simulates drilling scenarios, imposed by the environmental factors in offshore drilling. The Response Amplitude Operators (RAOs) of an industry-recognized semi-submersible MODU are modeled for all six degrees of freedom. A stochastic modeling of waves in the North Sea is used and heave disturbance induced by elevation motion of sea surface is modeled using the JONSWAP spectrum. A bond graph model of a MODU predicts axial vibration, torsional vibration, and coupling between axial and torsional vibration due to bit-rock interaction. Axial and torsional submodels use a lumped-segment approach. The model can predict the expected coupling between Weight On Bit (WOB), bit speed, and bit-rock interface conditions. A series of sensitivity analyses were performed to investigate the significance of MODU motion on WOB fluctuations.

Commentary by Dr. Valentin Fuster

Petroleum Technology: Integrity of Petroleum Wells

2015;():V010T11A014. doi:10.1115/OMAE2015-41561.

Well integrity related to carbon dioxide injection into depleted oil and gas reservoirs can be compromised by corrosion which can affect casing, downhole and surface equipment and well cement. Impact on well cement can cause overall degradation of set cement and lead to migration of carbon dioxide back to the surface. Thus, special types of cements should be used. One of the acceptable solutions is application of cement blends based on a mixture of Portland cement and pozzolans. The present paper deals with optimization of the cement slurry design containing zeolite which is nowadays widely used due to its high pozzolan activity potential. Cement blends containing 20%, 30% and 40% zeolite clinoptilolite were used. Cement slurries were optimized for application in slim hole conditions on CO2 injection wells on Žutica and Ivanić oil fields in Croatia (Europe), where an old and deteriorated production casing was re-lined with new smaller sized one. Results obtained by this study suggest that cement slurry containing zeolite can be optimized for application in well conditions related to CO2 injection and underground storage, ranging from a slim hole to standard size casing cement jobs which leads to an improvement of well integrity related to CO2 injection.

Commentary by Dr. Valentin Fuster
2015;():V010T11A015. doi:10.1115/OMAE2015-41756.

Cements in oil wells are exposed to high temperatures, a high pressures and a degrading environment. These affect the mechanical strength of the cement over time. Cement is often part of well integrity problems, sometimes creating leak paths to surface, but also allowing sour reservoir gases to corrode casings.

Poor cement bond quality and casing corrosion are two fundamental problems with oil well cements. This paper presents the effect of vegetable fiber, nano- and micro particle additives on cement slurry. The mechanical strength of the cement plugs were analyzed through sonic measurement and uniaxial compressive test. The internal structure of the cement plugs were analyzed through Scanning Electron Microscope (SEM).

The test results show an improved internal structure, higher load carrying capacity, longer deformation and higher modulus of resilience.

Commentary by Dr. Valentin Fuster
2015;():V010T11A016. doi:10.1115/OMAE2015-41920.

The offshore oil and gas industry spends over $60bn per year on oil and gas wells and of this some $6bn, or around 10% is eaten up by geological and geotechnical problems such as stuck pipe, lost circulation, well bore instability, shallow water flows and other problems. On top of this are the environmental costs of the oil spills that can result from lost well control, and perhaps most importantly the human costs in terms of injuries and loss of life resulting from some of the worst incidents.

This paper lists the geohazards within and around a well, the drilling risks implied by these geohazards, and the impact they can have on the planning and drilling of offshore wells.

Current practice in geophysical and geotechnical site investigation techniques which, when correctly applied and interpreted, can help to reduce the risks and costs associated with the ‘Top-hole’ section is summarised and discussed (the Top Hole section is defined as the depth to the base of the first pressure containment string).

Finally, a systematic approach to assessing and mitigating top-hole geo-risks through a multi-disciplinary geoscience and engineering approach is described.

The authors are members of a working group of the Offshore Site Investigation and Geotechnics (OSIG) committee of the Society of Underwater Technology (SUT) who are drafting guidelines on the subject.

Commentary by Dr. Valentin Fuster
2015;():V010T11A017. doi:10.1115/OMAE2015-42115.

After Macondo incident a great effort is under way to improve the safety of deepwater drilling and production operations and enhance the capabilities of different well barrier to stop the oil spill on its earliest stages. This study is a part of that collective effort to make offshore operations safe and decrease the associated risks. The main objective of this study is to quantify and categorize the risk associated with a representative well in the Gulf of Mexico during its normal production operations. In order to achieve an appropriate balance between safety and economics of deepwater oil and gas operations, Quantitative Risk Assessment (QRA) techniques can be successfully used. Quantified risk is computed from the product of blowout frequency and volume of oil spilled as a consequence. Blowout frequency is calculated from Fault Tree Analysis (FTA) and spilled oil volume is estimated from simulating multiphase fluid flow and heat transfer in wellbores.

A large number wells are completed with some sort of bottom hole sand control elements to prevent production of sand. The failure of these control elements may have severe consequence and in some cases may result in uncontrolled hydrocarbon flow to the environment as well. A representative production well from the Mississippi Canyon in the Gulf of Mexico is selected for the for quantitative risk assessment (QRA) analysis. The well is completed with cased hole gravel pack and with sand control elements in place. The representative reservoir properties for this well are selected from the literature and uncertainties in properties are accounted for by fitting lognormal distribution and carrying out Monte Carlo simulations. P50 value for the reservoir properties from Monte Carlo simulation is used to find worst case discharge rates by using a commercially available multiphase flow simulator with black oil model.

A Fault Tree is constructed to find the blowout probability based on the equipment failure data. From the minimal cut set method the importance and sensitivity of different well barrier is analyzed and most important areas to focus on are identified. The analysis showed that the constructed fault tree is most sensitive to sand screen failures, followed by subsea production tree and delayed response to a situation of immediate concern.

Topics: Gulf of Mexico
Commentary by Dr. Valentin Fuster
2015;():V010T11A018. doi:10.1115/OMAE2015-42204.

With the recent exploration/discovery of deep-water reservoirs andcontinued developments of drilling and production, it remains very important to have a comprehensive and quantitative risk assessment ofthe drilling/production processes including effective response to deal with such disasters. What measures must be taken to recover from the disaster scenario of a hurricane impacting the same region in the aftermath of an oil spill? The Deepwater Horizon oil spill, the largest marine oil spill in history, was caused by an explosion on a semi-submersible drilling rig about 50 miles southeast of the Mississippi River delta on April 20, 2010. Catastrophic events such as oil spills have enormous impact for the local economy of the area and even for the local labor markets. Another regional disaster, Hurricane Katrina impacted Louisiana, Mississippi, and Alabama, as it ripped over the core of the Gulf of Mexico (GoM) producing zone, one of the important oil and gas production areas of the worldin 2005. Also, if acatastrophic disaster occurs and the emergency response supply chain is not adequately prepared, then the economic consequences of sucheventcan be huge. Whenever a disaster happens, another reaction to this event that should be considered is resiliency. It is the ability to reduce or remove potential losses due to disaster events.

The impact of different shocks on various aspects of a state’s economic performance is estimated using a Vector Autoregressive model (VAR). In this study, the dynamic response of a variety of industrial sectors in Louisiana to each of these disasters is considered. The responses of different impulses in this model are shown to demonstrate the interdependence of various time series data.

Commentary by Dr. Valentin Fuster
2015;():V010T11A019. doi:10.1115/OMAE2015-42257.

In this study an experimental work is conducted to investigate the shape and speed of an air bubble in a pipe filled with different viscous fluids and porous media. The experimental results are also compared with the Computational Fluid Dynamics (CFD) simulation. Multiphase flows are complex due to the infinitely deformable nature of interface in gas/liquid flows. If one of the phases is gas acts as dispersed phase in the form of bubble, then the complexity will arise from the non-uniform distribution of bubbles in the pipe cross-section and axial distance. Inclusion of different viscous fluids simulating the industrial scale hydrocarbon properties brings added challenge in understating the bubble rise, coalescence and breakup dynamics. Moreover, bubble rise and change of shape of bubble in porous media will bring additional complexity in the flow dynamics. The pipe used in the experiment and CFD was 11.6 cm ID and a length of 100 cm. Three situations were tested: i) an air bubble rising in stagnant water, ii) an air bubble rising in moving water, and iii) an air bubble rising in a stagnant water but filled with porous media with porosity of 27%. Preliminary CFD results indicate that an air bubble has an average velocity of 0.2468 m/s and 0.2524 m/s in stagnant water and moving water, respectively, which is very close to experimental results.

Commentary by Dr. Valentin Fuster
2015;():V010T11A020. doi:10.1115/OMAE2015-42319.

Sustained Casing Pressure (SCP) in petroleum wells poses environmental risk and needs to be removed using either downhole intervention or annular intervention methods. The latter method involves displacing the annular fluid above the top of the gas-leaking well cement with a heavy fluid to increase the hydrostatic pressure and stop the gas leak. Past field applications of the method failed — most likely due to incompatibility of the two fluids. In this study, a see-through scaled-down hydraulic analog of the well’s annulus was designed and used for video-taped displacement experiments with clear synthetic-clay muds and heavy (kill) fluids. The results show that only immiscible hydrophobic kill fluids provide effective displacement. The study demonstrates importance of controlled injection of the kill fluid to set out efficient buoyant settling and prevent initial dispersion. A side- (versus top-) injection geometry and the injection rate data are analyzed to develop empirical correlation of maximum injection rate for a given properties of the two fluids.

Commentary by Dr. Valentin Fuster

Petroleum Technology: Petroleum Production Systems Design and Analysis

2015;():V010T11A021. doi:10.1115/OMAE2015-41602.

Formation of hydrates is one of the many challenges faced in the offshore oil and gas industry. It may result in blockage of subsea pipelines and equipment, which may result in flow line rupture and process accident. Although extensive experiment study is conducted to better understand the nucleation of hydrates and their slug flow behavior in gas-water/oil systems. However, there is limited understanding regarding the effects of multiphase fluid dynamics and geometric scales on the formation/growth of hydrates in subsea pipelines. In this paper a multiphase lab scale flow loop set-up is proposed to study the effects of pipe diameter, wall roughness, solid particles and hydrodynamic properties. The multiphase development length of a pipe for varying geometric and flow parameters is also analyzed considering three phase mixture properties. This study will help in identifying the accurate development length for gas/liquid/solid multiphase flow.

Commentary by Dr. Valentin Fuster
2015;():V010T11A022. doi:10.1115/OMAE2015-41669.

This article outlines the aspects of inherent safety for the topside layout design of a floating liquefied natural gas (FLNG) facility. An FLNG plant requires a compact design; meanwhile, it needs the safest layout to tackle multi-dimensional safety issues. Thus, the layout of the facility is a paramount factor for ensuring its safety in a cost effective way. Three layouts are proposed and evaluated from the inherent safety perspective. The layout of the process area is mainly focused due to its higher risks. Integrated inherent safety index, cost index and domino hazard index are used to evaluate the three layouts in quantitative terms. An optimal layout is finally chosen based on both inherent safety and cost performance.

Commentary by Dr. Valentin Fuster
2015;():V010T11A023. doi:10.1115/OMAE2015-41671.

Well completion plays a key role in reservoir production as it serves as a pathway that connects the hydrocarbon bearing rock with the wellbore, allowing formation fluids (e.g. oil, gas, water) to flow into the well and then up to production facilities on the surface. Frac-packing completion (F&P) is a well stimulation technique that vastly increases the fluid transport capability of the near wellbore region in comparison with the original formation capacity by filling fractures and perforation tunnels with high-permeability proppant, thus enabling higher production rates for the same pressure drop. Hence, it is of interest for the production engineer to have an accurate description of the actual and predicted production performance in terms of pressure drop and flowrate after the F&P completion process is done. However, in developing a mathematical model of this scenario two critical challenges should be faced: (a) as fluid flows at high flowrates it begins to deviate from linear behavior, i.e. Darcy’s law is no longer valid, (b) compressible fluid flow behavior in the near wellbore region cannot be intuitively predicted due to the geometrical complexity introduced by the well completion (e.g. perforation tunnels and fractures). Additionally, this kind of mathematical model must take into account the existence of three different domains: reservoir (porous, low permeability), completion region (porous, high permeability), and free flow region.

In view of these complications, this study presents a computational approach to model and characterize the near wellbore region with F&P completion using computational fluid dynamics (CFD) modeling, combining a non-linear (non-Darcy or Forchheimer) real gas flow in porous media with a turbulence model for the free flow region. This study is classified into three parts: 1) verification case, 2) Darcy vs. non-Darcy flow, and 3) erosion analysis. All simulation cases are assumed to be isothermal, steady state gas flow. Streamlines are implemented to identify the possible kinds of flow regimes, or patterns, in the near wellbore region and it is shown that gas flow pattern can be high unpredictable. Turbulence production and erosional velocity limit are also analyzed. Finally, mathematical correlations for well completion performance of this particular case study are derived using data curve fitting.

In conclusion, the CFD approach has proven to be a powerful yet flexible computational tool that can help the production and/or reservoir engineer to predict flow behavior as well as production performance for a gas producing well with F&P completion, while providing an insightful graphical description of pressure and velocity distribution in the near wellbore region.

Commentary by Dr. Valentin Fuster
2015;():V010T11A024. doi:10.1115/OMAE2015-42081.

Compaction and sand migration are some of the main problems for the loosely consolidated and unconsolidated high rate gas reservoirs. A reliable estimation of the well productivity depends on accurate modeling of permeability and inertial effects. Therefore, the key objective of this paper is to quantify the flow parameters change in the case of compaction and sand migration, and the development of permeability and the non-Darcy coefficient correlations that can be used in reservoir simulations. The compaction effects are simulated by increasing grains diameters with the same ratio. Permeability and the non-Darcy coefficients are calculated from lattice Boltzmann method (LBM). Results indicate that permeability decrease is not directional and the change in permeability can be estimated from porosity change with a Kozeny-Carman type relation with an exponent of 3.2. A Kozeny-Carman type relation between the non-Darcy coefficient and permeability is also found with an exponent −1.303. For high compressibility reservoirs, estimation of the inertial effects from the correlations developed as a function of permeability and porosity may also lead to underestimation of the inertial effects.

Sand migration causes pore-throat plugging that leads to significant reduction in permeability. Permeability impairment due to sand or fines migration is usually estimated from Kozeny-Carman type relation based on porosity. There is no study in the literature on how the inertial effects are changed with permeability impairment due to sand or fines migration. Sand particle plugging locations are found from the network simulations for different pore volume reduction, and corresponding permeability and the non-Darcy coefficient are calculated from LBM. It is found that permeability change with sand plugging is direction dependent: permeability reduction in the flow direction is twice compared to other directions. Porosity reduction does not depend on only pore-throat plugging, porosity can be decrease due to compaction and pore-surface deposition. Therefore, a correlation is developed to estimate permeability from pore-throat sand concentration. Even though permeability change is directional, the trend between permeability and the non-Darcy coefficient is similar and the magnitude of exponent in Kozeny-Carman type relation is larger, −1.803, compared to that of compaction.

Commentary by Dr. Valentin Fuster
2015;():V010T11A025. doi:10.1115/OMAE2015-42271.

The discoveries of the Pre-salt oilfields have driven the development of new technologies to enable the production of the deepwater reservoirs. In this scenario, subsea pipelines play an important role. Analysis of the steady and transient flow inside the pipes should be addressed in the design, considering the variation of the fluid properties. In this context, a pipe flow simulator project has been developed to attend gas flow analysis for petroleum industry. In this project, the fluid compressibility factor (Z-factor) and the viscosity are considered function of the pressure, temperature and gas composition. The non-isothermal transient gas flow were calculated using the Method of Characteristics (MOC). The results shown the difference of the isothermal and non-isothermal steady state and transient flow.

Commentary by Dr. Valentin Fuster

Petroleum Technology: Petroleum Reservoir Engineering and Management

2015;():V010T11A026. doi:10.1115/OMAE2015-41155.

Wettability test is one of the most used tools for evaluating rock/fluid interaction in oils reservoir. In the present paper two carbonate outcrop rocks are evaluated for wettability alterations when subjected to brine injections of varying salinities and content of dissolved CO2. The evaluation included a qualitative appraisal via spontaneous imbibition tests and a quantitative assessment by the Amott-Harvey procedure. Rocks refer to limestone and dolomite samples with petro-physical properties similar to the Brazilian pre-salt reservoirs. Testing fluids are a medium gravity crude oil, seawater concentration brine, formation equivalent brine and the carbonated version of these brines. Results show additional oil recovery directly associated with wettability alteration provoked by brine concentration changes. Increments in recovery were observed independently if the brine concentration decreased or increased in the replacement process. For dolomites and limestone wettability changed in the direction of turning the rock from oil-wet to neutral wet. Tests carried out with equivalent carbonated brines show that similar alteration in the wetting properties also occur. Alterations were as well independent of the increase or decrease of the salt concentration in the brine changed. However, CO2 or its derived ions dissolved in the brines seem to inhibit the mechanism of wettability change when rocks are subject to changes in brine salt concentrations.

Topics: Carbon dioxide
Commentary by Dr. Valentin Fuster
2015;():V010T11A027. doi:10.1115/OMAE2015-41446.

In mature fields, low oil production, increased gas production and water fractional flow of low pressure reservoir combined with the mobility ratio between the gas and oil feed contacts the w/o induced by the oil extraction process are accentuated in naturally fractured reservoirs (NFR) -. It is common N2 injection for pressure maintenance and decline of oil production; however N2 causes channeling towards producing wells. In various fields - NFR, closure of oil production by this mechanism loss value make unprofitable oil production and surface facilities for handling demanding high volume gas and / or water or gas production out of specification. In volumes estimated residual oil trapped in areas invaded by the gas cap and in areas of lower conductivity can be recovered if it has clearly identified enhanced recovery processes. Previous efforts to this work results showed potential benefits in terms of increased oil production and the significant reduction of Gas-Oil Ratio (GOR) and the technical and economic feasibility of using this type of process with surfactants developed specifically for the conditions of this area The technology tested and evaluated under methodological process is based on new supramolecular complexes wettability modifier, corrosion inhibitor and able to generate stable foams under high pressure, temperature and salinity, which penetrate and invade the channels of high conductivity formation cause decreased flow of gas by reducing gas mobility. The product in the liquid phase diffuses into the channels of lower conductivity which cannot penetrate the foam, and by spontaneous imbibition mechanism resulting from the change of wettability of the rock surface and reducing interfacial tension and favors an increase the oil recovery factor in naturally fractured reservoirs. The application of a methodological process allowed the parameters measurement and evaluation of test results, visualizing future opportunities for the new chemicals. This project was approved after evaluation from a process of allocation of federal funds.

With the purpose of defining the further steps in the search for the chemicals stability and risk mitigation stages of industrial upgrading for the complexity the NFR, the following discussion is presented.

In order to accelerate the knowledge of new technologies and its deployment on the field, PEMEX has diversified the efforts, to achieve the principal goals regarding new technologies. This will provide greater ability to assess best practices and technologies. To evaluate the efforts of companies a performance assessment model was designed and apply from 2008, which takes into account the integral complexity of each technology to attend the specific challenges from an Asset and to be fair in comparing the results obtained for the particular design of the test. The aim of this paper is to describe the results and the methodology used for developing the performance evaluation and identifying the new opportunities in the state of the art of these tests.

Commentary by Dr. Valentin Fuster
2015;():V010T11A028. doi:10.1115/OMAE2015-42230.

A key process in the oil industry to make decisions is data collection. To improve productivity it is important data and information analysis. For many organizations is not profitable data automation, which has an impact in the way organizations, collect data. Data collection is taken by manual processes that create uncertainty for analysis because it is not reliable. As consequence, making a decision has not the planned results. After working for many years in the oil industry was identified:

1. People collecting data in a manual process normally by using a piece of paper which could be lost or damage.

2. After taking data at the well, data are brought to the office. Then, data are downloaded by another worker in computer software. It can be modified intentionally or not.

3. Accuracy of data collection activity is carried out. How do we know if the staff really went to work area?

4. Training to new staff, lack of experience?

5. There are “risks zones” due vandalism, facilities are damaged by people who stole devices which causes great money losses to companies.

All these mentioned factors affect decision making which has a big impact in the production process. This application helps the whole process from collection data until data are registered in databases.

This application considered several observations, suggestions and comments from people involve in the oil industry, especially at the production area. As a result, it is a tool that support data collection, standardize information in databases, improve data quality (it doesn’t matter localization), shows time and photographic position in a mobile device.

Information is generated digitally taking advantage of easy handling.

To summarize advantages of the whole system:

• Reduce time of the data re-collection process

• Improve data quality

• Reduce amount of people working on data registration

• Data reliability

• Support decisions making

• Minimize the use of paper in order to help ambient environment

• Improve vehicle logistics

• Minimize use of gasoline which helps to reduce costs

• Help to optimize routes for vehicles on the field

• Productivity, Maintenance, etc., reports can be generated

• Vandalism is not a problem

Topics: Data collection
Commentary by Dr. Valentin Fuster
2015;():V010T11A029. doi:10.1115/OMAE2015-42327.

As part of its strategic plan 2014–2018 Pemex Exploration and Production (PEP) has decided to modify the organizational structure in order to change from a function based structure to a new one based in process, supported on three fundamental axes: People, Processes and Technology. On this direction, it has been assigned to the Technical Resources Management Vice-presidency the responsibility to implement a strategy that will enable to improve performance into the Assets of the Marine Region. This paper presents the experiences and achievements reached by implementing the strategy of “Integrated Production Management by Processes” which goal is to create and implement a management model that will contribute to the optimization of the Asset performance, integrating through the people, management processes, workflows and information and communication technologies.

The “Integrated Production Management by Processes” model, is based on five elements that work integrated and coordinated way; these are:

• Organizational issues.

• Work methodologies.

• Information management.

• Monitoring key performance indicators (KPI).

• Production costs management

The proposal on this paper is based on developing a business process management methodology for PEMEX, by applying the 5 elements of the model to measure current performance of the production assets in order to find the existing gaps between the current management model and the Integrated Production Management by Processes and implement an action plan to close those gaps. In order to homologate and standardize the measurements in PEMEX’s assets, a Capability Maturity Model was developed according to the ISO 9004-2010 and Mexican Standard NMX-CC-9004-IMNC-2009. The maturity model allows weighting each one of the 5 elements into 5 dimensionless levels. The lowest level 1 means that the asset is in the initial stage and it has the Vision of a Functional Management; on the other hand, the highest level 5 means that asset has implemented the new model and has reached a Sustainable Management. To implement the Integrated Production Management by Processes, assets need to demonstrate that Level 4 has been reached.

Commentary by Dr. Valentin Fuster

Petroleum Technology: Petroleum Wells: Production and Operation

2015;():V010T11A030. doi:10.1115/OMAE2015-41261.

There is a large number of subsea production wells offshore Norway approaching the end of their lifetime. Considering high spread rate of semisubmersible rigs, abandonment operations of these wells will be quite expensive. Moreover, Plug and abandonment (P&A) can easily contribute with 25% of the total costs of drilling for exploration wells offshore Norway. Hence it is of great importance to seek approaches and solutions to reduce the P&A cost. This paper reviews some possible new ways and also alternative technologies as the solutions to cut down the P&A expenses. Some of these technologies are now being used offshore Norway.

In the first section of this paper, challenges of performing P&A operations offshore Norway together with the main cost drivers are discussed. It is then briefly argued how to consider issues such as barriers setting depth, cementing depth and logging in the design and well construction phases to ease or avoid future P&A challenges. For hydrocarbon exploitation in the Barents Sea and Arctic regions it is important to take into account the P&A phase in the early stage of planning and development.

Light well intervention vessels as alternatives to semisubmersible rigs are recognized of being the largest contributor to cost saving. It will then be discussed to what extent vessel technologies can cut down the expenses for subsea abandonment. New ways of performing P&A can be another contributor to cost saving. It is shown how research and testing can assure the operators of new ways for performing P&A. Retrieval of production tubing is a challenging suboperation such that it imposes significant cost to subsea well abandonment. There have been performed studies on how P&A could be performed with tubing left in hole and it is of interest to pursue this further. We will investigate how the abandonment operations can be simplified and be more cost efficient if the production tubing can be left inside the well where the basic assumptions for being able to do it is accounted for.

In addition, some complexities in abandonment operations can cause additional cost. An example of such complexities can be the need to establish two permanent barriers for potential permeable zones in overburden. It will be demonstrated how much can be saved with respect to cost if the regulations allow to ease some parts of abandonment operations.

In this study, a probabilistic approach as a systematic tool to produce unbiased results is applied to quantify cost savings of new alternatives compared to the traditional ones.

Commentary by Dr. Valentin Fuster
2015;():V010T11A031. doi:10.1115/OMAE2015-41899.

Monitoring and control of subsea systems in remote ultra deep water scenarios is challenging as well as an opportunity for development and application of new technologies. One of the major problems is providing continuous power to sensors and actuators, independent of electrical umbilical cables. A conventional solution is the use of electrochemical batteries. However, problems can occur using batteries due to their finite lifespan. The need for constant replacement in remote locations can become a very expensive task or even impossible. Piezoelectric energy harvesters have received great attention for vibration-to-electric energy conversion over the last years. The evaluation of the power output of devices for different excitation frequency and amplitude of vibration has an important role in the design of such devices. This work describes the methodology to design a prototype that can be used in a pipe subjected to flow induced vibrations. Numerical model has been developed to reproduce the electromechanical coupling mechanism aiming at estimating the output voltage of the piezoelectric harvester. The results show the potential of piezoelectric materials for this application.

Commentary by Dr. Valentin Fuster
2015;():V010T11A032. doi:10.1115/OMAE2015-41923.

The use of shape memory alloys (SMA) in smart sensors and actuators is already well established in many areas such as biomedical and aerospace engineering. Likewise, SMA’s have an enormous potential for offshore oil and gas applications. They can be used, for example, in active vibration control devices or in deep water valves as actuators. In this work, two different prototypes of SMA actuation valves are developed — a linear and rotate sliding sleeve. Several tests were performed to determine the maximum force, maximum displacement of the devices. In parallel, numerical simulations using constitutive model of shape memory alloy are carried out to capture the behaviour of SMA actuators under different thermo-mechanical loadings.

Commentary by Dr. Valentin Fuster
2015;():V010T11A033. doi:10.1115/OMAE2015-42258.

The gas hydrates problem has been growing in offshore deep water condition where due to low temperature and high pressure hydrate formation becomes more favorable. Several studies have been done to predict the influence of gas hydrate formation in natural gas flow pipeline. However, the effects of multiphase hydrodynamic properties on hydrate formation are missing in these studies. The use of CFD to simulate gas hydrate formation can overcome this gap. In this study a computational fluid dynamics (CFD) model has been developed for mass, heat and momentum transfer for better understanding natural gas hydrate formation and its migration into the pipelines using ANSYS CFX-14. The problem considered in this study is a three-dimensional multiphase-flow model based on Simon Lo (2003) study, which considered the oil-dominant flow in a pipeline with hydrate formation around water droplets dispersed into the oil phase. The results obtained in this study will be useful in designing a multiphase flow metering and a pump to overcome the pressure drop caused by hydrate formation in multiphase petroleum production.

Commentary by Dr. Valentin Fuster

Petroleum Technology: Well Drilling Fluids and Hydraulics

2015;():V010T11A034. doi:10.1115/OMAE2015-41264.

Gas hydrates are solid substances consisting of water and gas which are stable under high pressure and low temperature conditions. After Davy discovered chlorine hydrate in 1810, gas hydrates from natural gas were found to be the reason for gas pipeline plugging in 1934 by Hammerschmidt. In 1965, the Russian scientist Makogon discovered natural gas hydrate deposits. This was the beginning of research in the geological occurrence of the gas hydrates.

Today, hundreds of gas hydrate wells for exploration have been drilled all over the world in the permafrost and deep sea regions. Several big projects for gas hydrate research and exploration have been financed by Japan, India, Korea, China and the USA. It is assumed that the amount of carbon in natural gas hydrates is twice the amount present in oil, gas and coal together. This makes them interesting as a future energy source. To drill into horizontal layers filled with gas hydrates in the pores, directional wells are needed.

To achieve an adequate cutting transport, a high performance drilling fluid has to be used instead of sea water. The drilling fluid must be able to keep the gas hydrate reservoir stable while drilling and prevent the formation of secondary gas hydrates in the liquid. Moreover, the gas hydrate cuttings should not dissociate on their way to the surface. To avoid altering of the drilling fluid due to water and gas produced as a result of gas hydrate dissociation, cuttings should be kept stable to separate them from the fluid like any other rock cuttings by the surface equipment.

To prevent gas hydrate formation, thermodynamic inhibitors, like salt, glycols or methanol are used. Also, kinetic inhibitors are added to the drilling fluid to prevent gas hydrate agglomeration and formation for a period of time. Well known kinetic inhibitors are polyvinylpyrrolidone (PVP), polyethylene glycol (PEG) and polyvinylcaprolactam (PVCap).

Although ethylene glycol (EG) is seen as a thermodynamic inhibitor for gas hydrates, it is shown in this study that it is able to stabilize methane hydrate significantly. For the investigation, a high pressure cell with pressures up to 8.5 MPa was used. The equilibrium point of methane hydrate was detected. Solutions with PVP, PEG, hydroxyethylcellulose (HEC), Sodium dodecyl sulfate (SDS) and a kinetic inhibitor containing EG were tested (concentrations from 1 to 10 wt.‰). PVP, PEG and HEC could not stabilize gas hydrates at the test condition. SDS showed both a stabilizing and promoting effect. EG can significantly stabilize gas hydrates.

Topics: Methane hydrate
Commentary by Dr. Valentin Fuster
2015;():V010T11A035. doi:10.1115/OMAE2015-41370.

Assembling or dismantling drillstring sections during tripping operations results in a periodically accelerated or decelerated motion of the drillstring in the borehole. While running in or pulling out of hole the drillstring induces a flow of displaced fluid and a pressure change in the borehole. These pressure changes can be divided into two components: First, the “steady” pressure change associated with the mud viscous friction; and second, the pressure fluctuations caused by induced acceleration of the drilling fluid. Pressure surges are especially dangerous for the uncased well sections and at the bottom of the well, because they can damage and destroy the wellbore. The accurate prediction of pressure fluctuations is significant for wells where the pressure must be maintained within a narrow range to enable safe drilling and completion of the well. Sudden pressure changes in such wells may lead to the so-called water-hammer effect that can be observed in wells when pump operation modes change or when the string is accelerated. A large-scale water-hammer effect may damage the uncased section of a well, leading to fractures or formation fluid inflow.

The objective of this paper is to estimate the magnitude of the pressure surges caused by accelerated movement of the drillstring. A mathematical model was formulated to describe the unsteady behavior of flow rate and pressure change along the well. The model involves a one-dimensional system of equations, which are a modification of the equations for hydraulic shocks in the annulus, and the cylindrical part of a well.

When frictional losses are neglected, it is possible to derive an exact analytical solution of the problem. This analytical solution was used to estimate the maximum and minimum pressure in the borehole.

When combined with the methods for frictional pressure losses, the suggested method can predict the pressure change in a wellbore while tripping. Newtonian and power law fluids were considered for the parameter study.

Commentary by Dr. Valentin Fuster
2015;():V010T11A036. doi:10.1115/OMAE2015-41552.

This paper present experimental study conducted on rheology of hydroxyethyl cellulose (polymer) based foams. The effects of foam quality, wall-slip, and polymer concentration on foam rheology have been experimentally investigated using a circulating flow loop. Foam quality and flow rate were varied from 50 to 80 percent and 1 to 52 L/min, respectively. To identify the existence of wall-slip, tests were performed using different diameter (13.4, 19.6 and 31.8 mm ID) pipe viscometers.

Experimental results show expected trends; pressure loss increased with increasing flow rate and reduced with increasing pipe diameter. Slight wall-slip was observed in the small diameter viscometer. However, the measurements obtained from other viscometers do not indicate wall-slip. All tested foams exhibited strong non-Newtonian behavior, which increases with foam quality and polymer concentration. The rheology of foams best fits the power-law fluid model. Applying regression analysis, new correlations have been developed to predict rheology of polymer-based foams.

Commentary by Dr. Valentin Fuster
2015;():V010T11A037. doi:10.1115/OMAE2015-41749.

Throughout the last decades, the design and performance of the primary solid control devices have changed significantly. Some five decades ago, the circular motion shakers dominated the marked. These shakers operated by sending the drilling fluid downhill a vibrating screen. Thereafter appeared the elliptical motion or linear motion shakers where the cuttings particles were vibrated upwards a tilted screen. Onto these shakers, the use of double screen decks and finally triple screen decks became common. Within the last years also the vacuum devices appeared.

Throughout the last two decades, there has been an effort to increase the g-forces on these shakers and the industry seems to have preferred the high g-force devices recently. Laboratory studies, however, has indicated that the very high g-forces are not necessary to perform proper solids control. Instead, different vibration modes interacts with the gel structure of the drilling fluid and remove yield stresses. Hence, the fluid becomes mobile for flow through the screen.

Flow through screens is strongly dependent on the extensional properties within the drilling fluid rheology. Drilling fluids with high extensional viscosity seldom has a very strong gel structure, and are generally not affected equally much by vibrations. This explains why solids control is more difficult using a KCl/polymer water based drilling fluid than if using an oil based drilling fluid.

This article focuses on describing how the drilling fluid rheological properties alter during primary solids control. It is based on theoretical analysis, rheological studies in the laboratory and finally on practical applications in two recent exploration drilling operations. The solids control efficiency resulting from using different screen configurations is outside the scope of this article, as this topic requires a higher focus on separation technology.

Topics: Fluids , Solids , Drilling , Rheology
Commentary by Dr. Valentin Fuster
2015;():V010T11A038. doi:10.1115/OMAE2015-41759.

Drilling fluid plays a key role in an efficient drilling operation to minimize problems such as wellbore collapse, circulation losses and stuck pipe. Well instability problems are costly as they increase the non-productive time and the overall budget (1) (2). Well instability problems controlled by designing appropriate mud density and fluid properties that controls the well. The fracture sealing ability of a drilling fluid is one very important of the drilling mud.

This paper presents design of water-based drilling fluids and results from laboratory experiments to quantify the loss circulation performance of drilling fluids.

Because it is preferable to use oil-based muds in some well sections, the paper will also include a recent study on how to minimize losses when using oil based muds. Here uses of micro/nanoparticles have shown to reduce filtrate losses and to build barriers that are more efficient during circulation loss events.

All the tests presented are at low temperature, which is suitable for Artic environments.

Commentary by Dr. Valentin Fuster
2015;():V010T11A039. doi:10.1115/OMAE2015-41762.

In this study a new experimental technique, particle image shadowgraph (PIS), is used to investigate the settling velocity of natural sand particles in Power-law fluids. The particle settling velocity measurements are conducted within the Reynolds number of range of 0.01 to 17.00. Natural sands with mean sieve diameters in the range, 0.35 mm – 1.4 mm, are used. Six different equivalent diameter definitions are used to characterize size of the natural sand particles. Using the size and shape measurements in conjunction with PIS, correlations between the mean sieve diameter and equivalent diameters are obtained.

Empirical correlations for predicting the settling velocity of sand particles in Power-law fluids are developed. Multiple linear regression analyses are performed with each fluid data and empirical coefficients for the models are also reported as functions of n and K. The models presented in the study give an average error of less than 20%. In addition, the multiple linear regression tools are applied to enhance the efficiency of the correlations by 3–5%. One of the major contributions of this study is that one can use any associated diameter to predict the settling velocity, which leads to greater flexibility.

Commentary by Dr. Valentin Fuster
2015;():V010T11A040. doi:10.1115/OMAE2015-41896.

A very important aspect in highly inclined wellbores is the mechanical friction. For extended reach drilling (ERD) and through tubing extended reach drilling (TTERD) this can be a limiting factor. Friction caused by the contact between the drill string and the well casing or borehole is dependent to the drilling weight and fluid properties. Drilling fluids play an important role on mechanical friction and using oil based drilling fluids with higher lubricity can reduce torque and drag behavior and minimize stick and slip. Reducing mechanical friction will improve drilling efficiency in general, and will in particular enable longer reach for ERD wells.

This paper presents results from experimental laboratory tests where mechanical friction has been investigated. The experiments have been conducted as part of a project in the Tribolab at Luleå University of Technology in cooperation with Det norske Oljeselskap.

Friction behavior has been investigated for different drilling fluids; water based and oil based drilling fluids both with and without solid particles. A pin on disc setup was used for these experiments where a spherical steel pin was sliding on a rotational disc made of granite. Friction force has been measured in constant sliding speed and in presence of particles in wet condition. The test results show that mechanical friction in general is smaller with oil based than water based drilling fluids in the presence of solid particles. In addition, the friction coefficient increases when solid particles were added to the lubricants.

Such experiments in a tribology laboratory are important to identify the effect of drilling fluids on mechanical friction from a basic point of view and isolated from all other wellbore parameters. It is interesting to monitor if the results from this setup can have quantitative relevance also for field situations and such comparison should be done as follow up. Test results and the experimental approach could therefore be of value for any one working with drilling and well construction.

Topics: Friction , Fluids , Drilling
Commentary by Dr. Valentin Fuster
2015;():V010T11A041. doi:10.1115/OMAE2015-41901.

One important requirement for a drilling fluid is the ability to transport the cuttings out of the borehole. Improved hole cleaning is a key to solve several challenges in the drilling industry and will allow both longer wells and improved quality of well construction. It has been observed, however, that drilling fluids with similar properties according to the API standard can have significantly different behavior with respect to hole cleaning performance. The reasons for this are not fully understood.

This paper presents results from flow loop laboratory tests without and with injected cuttings size particles using a base oil and a commercial oil based drilling fluid. The results demonstrate the importance of the rheological properties of the fluids for the hole cleaning performance. A thorough investigation of the viscoelastic properties of the fluids was performed with a Fann viscometer and a Paar-Physica rheometer, and was used to interpret the results from the flow loop experiments.

Improved understanding of the fluid properties relevant to hole cleaning performance will help develop better models of wellbore hydraulics used in planning of well operations. Eventually this may lead to higher ROP with water based drilling fluids as obtained with oil based drilling fluids. This may ease cuttings handling in many operations and thereby significantly reduce the drilling cost using (normally) more environmentally friendly fluids.

The experiments have been conducted as part of an industry-sponsored research project where understanding the hole cleaning performance of various oil and water based drilling fluids is the aim. The experiments have been performed under realistic conditions. The flow loop includes a 10 meter long test section with 2″ OD freely rotating drillstring inside a 4″ ID wellbore made of concrete. Sand particles were injected while circulating the drilling fluid through the test section in horizontal position.

Commentary by Dr. Valentin Fuster
2015;():V010T11A042. doi:10.1115/OMAE2015-41911.

Drilling fluids for oil wells must meet a number of requirements, including maintaining formation integrity, lubricating the drill string, and transporting cuttings to the surface. In order to satisfy these needs, drilling fluids have become increasingly complex and expensive. To ensure safe and efficient drilling, it is vital for the drilling operator to be able to make a qualified choice of fluid appropriate for each individual well.

API/ISO standards specify a set of tests for characterization of drilling fluids. However, fluids that are tested to have equal properties according to these standards are still observed to perform significantly different when used in the field. The aim of the full project is to provide a thorough comparison of drilling fluids in particular with respect to hole cleaning performance, in light of the issues presented above. As part of this investigation we here present results for two oil based drilling fluids, as well as for the corresponding base oil. The drilling fluids differ in composition by varying fraction of base oil, and thus density and water content.

The fluids have been tested according to the API standard, and further, viscoelastic properties have been examined using an Anton Paar rheometer. The rheological test campaign includes determination of the linear viscoelastic range (LVER), viscosity and yield point, thixotropic time test, and temperature dependence of rheological parameters.

Further, it is demonstrated how the rheological data may be used to interpret data from ongoing full scale flow loop experiments with the same fluids. In a more general context, the rheological test campaign of the drilling fluids is expected to make a crucial contribution for the petroleum industry in explaining observed differences in hole cleaning properties beyond what todays API/ISO industry standard provides.

Commentary by Dr. Valentin Fuster

Sorry! You do not have access to this content. For assistance or to subscribe, please contact us:

  • TELEPHONE: 1-800-843-2763 (Toll-free in the USA)
  • EMAIL: asmedigitalcollection@asme.org
Sign In