Guest Editorial

J. Energy Resour. Technol. 2008;130(4):040301-040301-1. doi:10.1115/1.3042144.

Unconventional resources, particularly natural gas that is uneconomic without advanced technologies, are forecasted by the United States Energy Information Administration (EIA) to play an increasingly important role in the energy supply of the United States during at least the next 30 years. As conventional energy sources are depleted, these unconventional resources will also become more important throughout the world in the future. The technologies to develop these resources are developing rapidly, and four papers presented at OMAE2007 and selected for this special issue of JERT illustrate important developments that are underway.

Commentary by Dr. Valentin Fuster

Guest Editorials

J. Energy Resour. Technol. 2008;130(4):040302-040302-1. doi:10.1115/1.3050251.

The occurrence of multiphase flow is inevitable in hydrocarbon production, transportation and processing. The problems associated with multiphase flow still challenge industry and research institutions alike. In this special issue of JERT, there are five papers covering various aspects of multiphase flow in production, transportation and processing. A brief summary of the papers is provided below.

Commentary by Dr. Valentin Fuster

Research Papers: Natural Gas Technology

J. Energy Resour. Technol. 2008;130(4):042701-042701-13. doi:10.1115/1.3000101.

A novel gas-liquid cylindrical cyclone (GLCC© , ©The University of Tulsa, 1994), equipped with an annular film extractor (AFE), for wet gas applications has been developed and studied experimentally and theoretically. Detailed experimental investigation of the modified GLCC has been carried out for low and high pressure conditions. The results show expansion of the operational envelope for liquid carry-over and improved performance of the modified GLCC. For low pressures, the modified GLCC can remove all the liquid from the gas stream, resulting in zero liquid carry-over (separation efficiency=100%). For high pressure conditions, the GLCC with a single AFE has separation efficiency >80% for gas velocity ratio, vsg/vann3. A mechanistic model and an aspect ratio design model for the modified GLCC have been developed, including the analysis of the AFE. The model predictions agree with the experimental data within ±15% for low pressure and ±25% for high pressure conditions.

Commentary by Dr. Valentin Fuster

Research Papers: Petroleum Engineering

J. Energy Resour. Technol. 2008;130(4):042901-042901-9. doi:10.1115/1.3000128.

The fundamental understanding of the dynamic interactions between multiphase flow in the reservoir and that in the wellbore remains surprisingly weak. The classical way of dealing with these interactions is via inflow performance relationships (IPRs), where the inflow from the reservoir is related to the pressure at the bottom of the well, which is a function of the multiphase flow behavior in the well. A steady-state IPRs are normally adopted, but their use may be erroneous when transient multiphase flow conditions occur. The transient multiphase flow in the wellbore causes problems in well test interpretation when the well is shut-in at the surface and the bottomhole pressure is measured. The pressure buildup (PBU) data recorded during a test can be dominated by transient wellbore effects (e.g., phase change, flow reversal, and re-entry of the denser phase into the producing zone), making it difficult to distinguish between true reservoir features and transient wellbore artifacts. This paper introduces a method to derive the transient IPRs at bottomhole conditions in order to link the wellbore to the reservoir during PBU. A commercial numerical simulator was used to build a simplified reservoir model (single well, radial coordinates, homogeneous rock properties) using published data from a gas condensate field in the North Sea. In order to exclude wellbore effects from the investigation of the transient inflow from the reservoir, the simulation of the wellbore was omitted from the model. Rather than the traditional flow rate at surface conditions, bottomhole pressure was imposed to constrain the simulation. This procedure allowed the flow rate at the sand face to be different from zero during the early times of the PBU, even if the surface flow rate is equal to zero. As a result, a transient IPR at bottomhole conditions was obtained for the given field case and for a specific set of time intervals, time steps, and bottomhole pressure. In order to validate the above simulation approach, a preliminary evaluation of the required experimental setup was carried out. The setup would allow the investigation of the dynamic interaction between the reservoir, the near-wellbore region, and the well, represented by a pressured vessel, a cylindrical porous medium, and a vertical pipe, respectively.

Commentary by Dr. Valentin Fuster

Research Papers: Petroleum Transport/Pipelines/Multiphase Flow

J. Energy Resour. Technol. 2008;130(4):043001-043001-5. doi:10.1115/1.3000136.

Pigging is recognized as one of the most used techniques for removing wax deposits in pipelines. In an earlier paper, the mechanics of wax removal was studied using an experimental setup under dry conditions, i.e., no oil presence. In this study, the pigging experiments are conducted for both regular disk and by-pass disk pigs under flowing conditions. A new test facility was designed and constructed. The test section is 6.1 m (20 ft) long schedule 40 steel pipe with an inner diameter of 0.0762 m (3 in.). A mixture of commercial wax and mineral oil is cast inside the spool pieces for different wax thicknesses and oil contents. The wax breaking and plug transportation forces are investigated separately. The results indicated that the wax breaking force increases as wax thickness increases, and the wax plug transportation force gradient is independent of the wax plug length. In comparison to previous test results, the presence of oil reduced the wax plug transportation force. Experimental results also showed that the wax transport behavior of the by-pass pig is significantly different than that of the regular pig. The by-pass pig allows the oil to flow through the by-pass holes and mobilizes the removed wax in front of the pig resulting in no discernible wax accumulation in front of the pig. Therefore, no measurable transportation force was observed for the by-pass pig tests.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2008;130(4):043002-043002-12. doi:10.1115/1.3000137.

This study investigates theoretically and experimentally the slug damper as a novel flow conditioning device, which can be used upstream of compact separation systems. In the experimental part, a 3 in. ID slug damper facility has been installed in an existing 2 in. diameter two-phase flow loop. This flow loop includes an upstream slug generator, a gas-liquid cylindrical cyclone (GLCC© , ©The University of Tulsa, 1994) attached to the slug damper downstream and a set of conductance probes for measuring the propagation of the dissipated slug along the damper. Over 200 experimental runs were conducted with artificially generated inlet slugs of 50 ft length (Ls/d=300) that were dumped into the loop upstream of the slug damper, varying the superficial liquid velocity between 0.5 ft/s and 2.5 ft/s and superficial gas velocity between 10 ft/s and 40 ft/s (in the 2 in. inlet pipe) and utilizing segmented orifice opening heights of 1 in., 1.5 in., 2 in., and 3 in. For each experimental run, the measured data included propagation of the liquid slug front in the damper, differential pressure across the segmented orifice, GLCC liquid level, GLCC outlet liquid flow, and static pressure in the GLCC. The data show that the slug damper/GLCC system is capable of dissipating long slugs, narrowing the range of liquid flow rate from the downstream GLCC. Also, the damper capacity to process large slugs is a strong function of the superficial gas velocity (and mixture velocity). The theoretical part includes the development of a mechanistic model for the prediction of the hydrodynamic flow behavior in the slug damper. The model enables the predictions of the outlet liquid flow rate and the available damping time, and in turn the prediction of the slug damper capacity. Comparison between the model predictions and the acquired data reveals an accuracy of ±30% with respect to the available damping time and outlet liquid flow rate. The developed model can be used for design of slug damper units.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2008;130(4):043003-043003-10. doi:10.1115/1.3000103.

Marching algorithms are the rule rather than the exception in the determination of pressure distribution in long multiphase-flow pipes, both for the case of pipelines and wellbores. This type of computational protocol is the basis for most two-phase-flow software and it is presented by textbooks as the standard technique used in steady state two-phase analysis. Marching algorithms acknowledge the fact that the rate of change of common fluid flow parameters (such as pressure, temperature, and phase velocities) is not constant but varies along the pipe axis while performing the integration of the governing equations by dividing the entire length into small pipe segments. In the marching algorithm, governing equations are solved for small single sections of pipe, one section at a time. Calculated outlet conditions for a particular segment are then propagated to the next segment as its prescribed inlet condition. Calculation continues in a “marching” fashion until the entire length of the pipe has been integrated. In this work, several examples are shown where this procedure might no longer accurately represent the physics of the flow for the case of natural gas flows with retrograde condensation. The implications related to the use of this common technique are studied, highlighting its potential lack of compliance with the actual physics of the flow for selected examples. This paper concludes by suggesting remedies to these problems, supported by results, showing considerable improvement in fulfilling the actual constraints imposed by the set of simultaneous fluid dynamic continuum equations governing the flow.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2008;130(4):043004-043004-8. doi:10.1115/1.3000135.

The transport of unprocessed gas streams in production and gathering pipelines is becoming more attractive for new developments, particularly those in less friendly environments such as deep offshore locations. Transporting gas, oil, and water together from wells in satellite fields to existing processing facilities reduces the investments required for expanding production. However, engineers often face several problems when designing these systems. These problems include reduced flow capacity, corrosion, emulsion, asphaltene or wax deposition, and hydrate formation. Engineers need a tool to understand how the fluids travel together, to quantify the flow reduction in the pipe, and to determine where, how much, and what type of liquid that would form in a pipe. The present work provides a fundamental understanding of the thermodynamics and hydrodynamic mechanisms of this type of flow. We present a model that couples complex hydrodynamic and thermodynamic models for describing the behavior of fluids traveling in near-horizontal pipes. The model presented herein focuses on gas transmission exhibiting low-liquid loading conditions. The model incorporates a hydrodynamic formulation for three-phase flow in pipes, a thermodynamic model capable of performing two-phase and three-phase flash calculations in an accurate, fast, and reliable manner, and a theoretical approach for determining flow pattern transitions in three-phase (gas-oil-water) flow and closure models that effectively handle different three-phase flow patterns and their transitions. The unified two-fluid model developed herein is demonstrated to be capable of handling three-phase systems exhibiting low-liquid loading. Model predictions were compared against field data with good agreement. The hydrodynamic model allows (1) the determination of flow reduction due to the condensation of liquid(s) in the pipe, (2) the assessment of the potential for forming substances that might affect the integrity of the pipe, and (3) the evaluation of the possible measures for improving the deliverability of the pipeline.

Commentary by Dr. Valentin Fuster

Research Papers: Petroleum Wells-Drilling/Production/Construction

J. Energy Resour. Technol. 2008;130(4):043101-043101-6. doi:10.1115/1.3000123.

A state of the art graphical user interface program has been developed to predict and design the bottom-hole assembly (BHA) performance for drilling. The techniques and algorithms developed in the program are based on those developed by Lubinski and Williamson. The BHA program facilitates conducting parametric studies and making field decisions for optimal BHA performance. The input parameters may include formation class, dip angle, hole size, drill collar size, number of stabilizers, and stabilizer spacing. The program takes into consideration bit-formation characteristics and interaction, drilling fluid weight, drill collar sizes, square collars, shock absorbers, measurement while drilling tools, reamer tools, directional tools, rotary steerable systems, etc. The output may consist of hole curvature (buildup or drop rate), hole angle, and weight on bit and is presented in drilling semantics. Additionally, the program can perform mechanical analyses and can solve for the bending moments and reaction forces. Moreover, the program has the capability to predict the wellpath using a drill ahead algorithm. The program consists of a mathematical model that makes assumptions of 2D, static, and constant hole curvature, resulting in a robust computationally efficient tool that produces rapid reliable results.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2008;130(4):043102-043102-4. doi:10.1115/1.3000139.

The U.S. Department of Energy’s National Energy Technology Laboratory (NETL) established the Extreme Drilling Laboratory to engineer effective and efficient drilling technologies viable at depths greater than 20,000 ft. This paper details the challenges of ultradeep drilling, documents reports of decreased drilling rates as a result of increasing fluid pressure and temperature, and describes NETL’s research and development activities. NETL is invested in laboratory-scale physical simulation. Its physical simulator will have capability of circulating drilling fluids at 30,000 psi and 480°F around a single drill cutter. This simulator is not yet operational; therefore, the results will be limited to the identification of leading hypotheses of drilling phenomena and NETL’s test plans to validate or refute such theories. Of particular interest to the Extreme Drilling Laboratory’s studies are the combinatorial effects of drilling fluid pressure, drilling fluid properties, rock properties, pore pressure, and drilling parameters, such as cutter rotational speed, weight on bit, and hydraulics associated with drilling fluid introduction to the rock-cutter interface. A detailed discussion of how each variable is controlled in a laboratory setting will be part of the conference paper and presentation.

Topics: Drilling , Rocks , Fluids
Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2008;130(4):043103-043103-12. doi:10.1115/1.3000142.

Drilling costs are significantly influenced by bit performance when drilling in offshore formations. Retrieving and replacing damaged downhole tools is an extraordinarily expensive and time-intensive process, easily costing several hundred thousand dollars of offshore rig time plus the cost of damaged components. Dynamic behavior of the drill string can be particularly problematic when drilling high strength rock, where the risk of bit failure increases dramatically. Many of these dysfunctions arise due to the interaction between the forces developed at the bit-rock interface and the modes of vibration of the drill string. Although existing testing facilities are adequate for characterizing bit performance in various formations and operating conditions, they lack the necessary drill string attributes to characterize the interaction between the bit and the bottom hole assembly (BHA). A facility that includes drill string compliance and yet allows real-rock/bit interaction would provide an advanced practical understanding of the influence of drill string dynamics on bit life and performance. Such a facility can be used to develop new bit designs and cutter materials, qualify downhole component reliability, and thus mitigate the harmful effects of vibration. It can also serve as a platform for investigating process-related parameters, which influence drilling performance and bit-induced vibration to develop improved practices for drilling operators. The development of an advanced laboratory simulation capability is being pursued to allow the dynamic properties of a BHA to be reproduced in the laboratory. This simulated BHA is used to support an actual drill bit while conducting drilling tests in representative rocks in the laboratory. The advanced system can be used to model the response of more complex representations of a drill string with multiple modes of vibration. Application of the system to field drilling data is also addressed.

Commentary by Dr. Valentin Fuster

Reaearch Papers: Unconventional Petroleum

J. Energy Resour. Technol. 2008;130(4):043201-043201-6. doi:10.1115/1.3000096.

Decline curve analysis is the most commonly used technique to estimate reserves from historical production data for the evaluation of unconventional resources. Quantifying the uncertainty of reserve estimates is an important issue in decline curve analysis, particularly for unconventional resources since forecasting future performance is particularly difficult in the analysis of unconventional oil or gas wells. Probabilistic approaches are sometimes used to provide a distribution of reserve estimates with three confidence levels (P10, P50, and P90) and a corresponding 80% confidence interval to quantify uncertainties. Our investigation indicates that uncertainty is commonly underestimated in practice when using traditional statistical analyses. The challenge in probabilistic reserve estimation is not only how to appropriately characterize probabilistic properties of complex production data sets, but also how to determine and then improve the reliability of the uncertainty quantifications. In this paper, we present an advanced technique for the probabilistic quantification of reserve estimates using decline curve analysis. We examine the reliability of the uncertainty quantification of reserve estimates by analyzing actual oil and gas wells that have produced to near-abandonment conditions, and also show how uncertainty in reserve estimates changes with time as more data become available. We demonstrate that our method provides a more reliable probabilistic reserve estimation than other methods proposed in the literature. These results have important impacts on economic risk analysis and on reservoir management.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2008;130(4):043202-043202-7. doi:10.1115/1.3000104.

To meet future global oil and gas demands, the energy industry will need creative thinking that leads to the discovery and development of new fields. Unconventional gas resources, especially those in frontier (exploratory) basins, will play an important role in fulfilling future energy needs. To develop unconventional gas resources, we must first identify their occurrences and quantify their potential. Basin analog systems investigation (BASIN ) is a computer software that can rapidly and inexpensively evaluate the unconventional gas resource potential of frontier basins. BASIN is linked to a database that includes petroleum systems and reservoir properties data from 25 intensely studied North American “reference” basins that have both conventional and unconventional oil and gas resources. To use BASIN , limited data from a frontier or “target” basin are used to query the database of North American reference basins and rank these reference basins as potential analogs to the frontier basin. Based on analog comparisons, we can predict unconventional gas resources and make preliminary engineering decisions concerning resource development and the best drilling, completion, stimulation, and production practices to use in the frontier basin. Initial software validation shows consistent results. If a basin is selected as the target basin while the same basin is also in the reference basin list, the results show that the basin is a 100% analog to itself. Other basins in the reference basin list are less than 100% analogs. Also, BASIN performed favorably when it was tested against analog basin decisions made by of a team of industry experts. BASIN rapidly and inexpensively identifies and ranks reference basins as analogs to a frontier basin, providing insights to potential gas resources and indicating the preliminary best engineering practice for resource development. It is an effective tool that provides guidance to inexperienced professionals and new perceptions for seasoned experts.

Commentary by Dr. Valentin Fuster

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