bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mass Transfer on Multiphase Transitions in Low-Temperature CO2 Floods
Authors: Okuno R. , Xu Z. 
Published: September 2013

Abstract
Mixtures of reservoir oil and CO2 can exhibit complex multiphase behavior at temperatures typically below 120°F, where a third CO2-rich liquid (L2) phase can coexist with the oleic (L1) and gaseous (V) phases. The three-phase behavior is bounded by two types of critical endpoint (CEP) tie lines in composition space. The lower CEP (LCEP) tie line is where the two liquid phases merge in the presence of the V phase, and the upper CEP (UCEP) tie line is where the L2 and V phases merge in the presence of the L1 phase. Slim-tube tests reported in the literature show that low-temperature oil displacement by CO2 can result in high displacement efficiency of more than 90% when three phases are present during the displacement. The nearly piston-like displacements can be quantitatively reproduced in numerical simulations when the CEP behavior is properly considered. However, it is uncertain how multicontact miscibility (MCM) is developed through interaction of flow and three-hydrocarbon-phase behavior.
In this research, we analyze mass conservation on multiphase transition between two and three phases for the limiting three-phase flow, where the L1 phase is completely displaced by the L2 phase on the LCEP. The analysis indicates that mass transfer on multiphase transition occurs in the most efficient way for MCM development. Simple analytical conditions derived for MCM through three phases are applied to 1-D fine-scale simulations of CO2 floods using four and more components. Results show that the MCM conditions are nearly satisfied when the effect of numerical dispersion is small. MCM is likely developed through three hydrocarbon phases on the LCEP in the cases studied. This is consistent with analytical solutions of water and gas injection presented in the literature, where MCM is developed on a CEP for the aqueous, V, and L1 phases. For MCM cases in this research, the L2-V two phases are present upstream of the miscible front, but can also be miscible on the non-L1 edge of the UCEP tie line.
The limiting three-phase flow does not necessarily occur at the highest pressure for three-phase flow, especially when a heavy oil is displaced by solvent at low temperatures. This is a marked difference from the conventional MCM development through two phases, where the limiting two-phase flow typically occurs at the highest pressure for two-phase flow.
Three-phase flow gradually changes to two-phase flow with varying pressure in the presence of numerical dispersion. We show that mass transfer on multiphase transition becomes less efficient during the change until the three-phase region completely disappear.
Predicting Formation Pressures from Passive Magnetotelluric Technology
Authors: Manríquez Alberto López 
Published: September 2013

Abstract
Common practice in industry is to obtain geopressures from methodologies applied to data obtained from seismic or electrical logs. In this work, a passive high resolution magnetotelluric (HRM) method used for hydrocarbon exploration purposes is being proposed to predict geopressures for exploration purposes before drilling a well.
Recorded time data are processed through a 1-D inversion algorithm. Fourier transforms give the amplitude and phase data available for input into the algorithm to obtain electric, magnetic, and impedance profiles. These impedance values are used to obtain apparent resistivity values and these values are then processed following Eaton's approach based on the effective stress principle of one-dimensional consolidation, introduced by Terzaghi, to estimate formation pore pressures and fracture pressures. This is an effective stress approach that takes into account abnormal pressures caused by consolidation in a saturated porous media.
As with any other indirect method, the results reported in this work are interpretive. Results of a set of data are discussed. Through the comparison of these results with data obtained from correlating wells, similarities were found; however, some differences arose. Acknowledgement of the relative importance of the strengths and weaknesses of the methodology here proposed allows the identification of specific areas of interest where further investigation is recommended.
The significance of this work rests on the following concepts. First, because MT is currently being used to estimate apparent porosity, resistivity, and other subsurface properties, these outputs are used to add value to HRM by predicting from them estimated values of geopressures. Second, results of this proposed methodology are valuable for interpretation, correlation, and identification of abnormal pressure zones for exploration purposes. Finally, since results are integrated and presented in pressure profiles and equivalent density formats along depth of investigation, they could be useful for drilling and completion planning.
Petroleum Engineering Curricua: Are They Adequate for Technological Developments and Future Needs?
Authors: Mohamed A. Aggour 
Published: September 2013

Abstract
This paper presents a critical review and evaluation of petroleum engineering curricula of leading schools in the USA and the Middle East, and examines their adequacy for coping with technological developments and future industry needs. Potential changes to curricula structures and content are presented and examined considering the current industry emphasis on shale gas development. A proposal to establish an SPE accreditation system for petroleum engineering progams worldwide is also presented.
The objective is to set the stage for petroleum engineering educators and industry to jointly plan for and engage in taking decisive actions to improve petroleum engineering education.
A quick review of petroleum engineering curricula shows that we have been using the same structure and content for decades. While the industry is developing and adopting new technologies at a rapid pace, petroleum engineering education has experienced very little changes. While a limited number of courses experienced some changes such as including horizontal, multilateral and under balanced drilling in drilling engineering courses, the majority of courses are still using the materials developed in the 1960's. No curriculum adequately addresses the very important shale gas developments; indeed, many petroleum engineering faculty are not familiar with this area.
It is essential that both industry and academia collaborate to determine and prioritize industry needs and the ways to develop petroleum engineering education to meet these needs.
Comparison of Decline Curve Analysis Methods with Analytical Models in Unconventional Plays
Authors: Meyet Marie , Dutta Riteja , Burns Chris 
Published: September 2013

Abstract
Unconventional plays have moved to the forefront of the energy industry in the U.S. over the last five years due to advancements in technology and the overall abundance of producible hydrocarbons discovered near existing infrastructure. In the present economic climate, there is an increased interest in liquid rich plays, and because of the relatively limited historical production data available for these resources, there is a lot of industry discussion regarding future decline performance and estimated ultimate recovery (EUR) per well. The objective of this paper is to discuss the uncertainty associated with estimating reserves in U.S. unconventional plays using common decline curve analysis (DCA) methods in comparison to analytical modeling.
Broadly speaking, there are five common methods for estimating: use of analogs, volumetric analysis combined with an estimate of recovery efficiency, decline curve analysis (DCA), analytical models and numerical simulation. Among theaforementioneds, DCA is the simplest and often fastest way to estimate volumes. However, the theoretical basis for most DCA approaches does not apply to unconventional reservoirs, which introduces some uncertainty into estimation of volumes. Nevertheless, it is commonly applied because of its perceived simplicity.
Different unconventional DCA methods were compared with results of an analytical model generated using commercial software: the power law model (PLE), the logistic growth model (LGM), and Duong's method. The analysis was performed on various unconventional plays based on reservoir type and well geometry. All historical production data is gathered from public documents. The application of the DCA methods was also extended to various fluid types to determine their suitability for application in oil as well as gas reservoirs.
The results of the study show that comparing multiple DCA methods with an analytical model aids in the understanding of the range of uncertainty associated with the EUR of unconventional wells. The study also helps establish the most appropriate DCA methods for various reservoir types, well geometry, and fluid types. The results also suggest approaches for avoiding violating the SEC's guidelines for categorizing proven reserves.
Application of Inflow Control Device Technology and its Value Realization for Kuwait Oil Fields through Best Practices and Multidisciplinary Team Work
Authors: Al-Jasmi Ahmad K. , Siddiqui Mohammed A. , Al-Anezi Khalaf G. , Zaki Hasan 
Published: September 2013

Abstract
In the pursuit of maximizing oil production to meet the 2030 strategy of producing 4.5 MM bopd, KOC has adopted a massive plan of implementing new technologies through pilot trials. Some of the technologies successfully tested are fiber optic sensors for real time reservoir monitoring, horizontal wells for increased production through increased reservoir contact, inflow control device and interval control valves for improving cumulative production and managing reservoir uncertainties, multilateral wells to reduce well footprint with increased production and acid tunneling technology to gain oil from old wells in depleted reservoirs.
Horizontal wells are considered superior over conventional wells in terms of production improvement due to increased reservoir contact. Despite this, these wells pose severe production challenges due to variations in permeability, reservoir pressure, reservoir fluid properties and frictional pressure drop along horizontal section. Preventing water/gas breakthrough, equalizing inflow with minimizing pressure loss, minimizing annular flow and heel-to-toe effect, delay non-uniform water progress, avoiding by-passed oil, increasing sweep efficiency and ultimate recovery are some of the primary challenges that are required to be addressed for gaining optimum advantages of horizontal wells. One of the promising technologies to address all these challenges is the application of advanced completions, such as inflow control device (ICD) and interval control vale (ICV). These completions help to enhance hydrocarbon recovery and reserves management.
The technology was test trialed successfully through multidisciplinary team approach and best practices. The value addition of the technology was evaluated by interacting with major operators and service companies. The evaluation of ICD and ICV was done by inviting designs from all the major companies and appropriate systems were selected with respect to reservoir and fluid properties, maintaining the policies of commercial group. For the first pilot test, suitable wells and systems were selected to avoid drawbacks that might lead to pilot failure and eventually disapproval of the technology from top management. This paper describes the results of the first ICD and ICV pilots, methodology, best practices and selection criteria that ultimately resulted into large scale field implementation of these technologies.
Evaluation of Multi-Objective Methods for Portfolio Tradeoff Analysis
Authors: Kostuik K. , Valdez A. A. , Bordovsky J. , Mu Y. , Faig C. 
Published: September 2013

Abstract
Recent advances in multi-objective optimization technology enable improved solution quality, scalability, and flexibility for portfolio analysis.
A multi-objective evolutionary algorithm (MOEA) with innovative constraint handling was used for portfolio planning of offshore exploration & production projects. The MOEA method was used for tradeoff analysis and portfolio optimization. In order to facilitate direct comparison with alternative methods, a multi-objective evaluation framework was developed, and a simplified test problem was derived from historical planning data. The MOEA method was compared to three other portfolio planning methods: rank & cut, sample & filter, and mixed integer linear programming (MILP).
The study highlighted that the evaluation of multi-objective methods is itself a multi-objective problem. Methods that performed well on some criteria performed poorly on others, and no method dominated on all criteria. The presence of planning constraints proved critical, with unconstrained problems being easy to solve with traditional rank & cut, and constrained problems requiring some type of optimization method.
The MOEA method demonstrated several advantages. Even though the test problem was designed specifically to be a good match for the MILP method, the MOEA method was competitive on all criteria and excelled on solution spread, flexibility, and scalability. Published MOEA methods have the potential to enable new types of portfolio tradeoff analysis, although successful applications will likely require enhancements to published constraint handling techniques.
Multi-objective methods are in the early phases of petroleum industry adoption, so there is little knowledge of appropriate solution method evaluation criteria. The study highlights important and commonly overlooked issues in evaluating multi-objective methods.
‘LOSC’ Simulation: A Key to Introduce Heterogeneities in Turbidite Channel Complexes (Offshore Congo)
Authors: Gaillot J. , Labourdette R. , Bez M. , Bui T. 
Published: September 2013

Abstract
Hydrocarbon-bearing turbidite reservoirs are complex features, and their description needs to take into account heterogeneities at seismic and sub-seismic scales. The morphology and internal distribution of elementary channels are dependent on depositional setting, which controls the distribution of the main heterogeneities. The internal architecture of a channel complex is composed of multiple individual (elementary) channel stacks formed during repeated erosion/deposition cycles. A turbidite channel is not a simple funnel transporting sand to deep-sea areas but also may preserve slumps, collapse breccias and internal levees on its borders, resulting in the formation of internal heterogeneities (below seismic resolution). The sideways and down-dip movements of elementary channels in turbidite complexes show two typical patterns: lateral migration and vertical stacking. The spatial distribution of heterogeneities at the elementary channel margin is therefore constrained by the different channel patterns. Seismic data only display the outside geometry of channel lateral stack, i.e. a turbidite fairway.
Complexes of Laterally Offset Stacked Turbidite Channels (LOSCs) require a description based on the scale of individual channel bodies. The most common representation of channels in a fairway is by stochastic object modeling; i.e. populating the observed fairway with realistic forms representing individual channels, but with no established consistency between the individual channels. Furthermore, one essential characteristic of LOSCs is that they evolve by progressive migration laterally and/or down-dip. Stochastic object modeling provides an inadequate representation of this progressive evolution, and consequently a poor rendering of the heterogeneity distribution in the reservoir.
The methodology we propose consists of defining a realistic succession of individual channels that can accurately build the fairway observed on seismic. ‘Realism’ is defined using criteria from the shape of individual channels, and based on the amount of displacement necessary between successive episodes based on seismic interpretation.
This workflow, based on geometrical modeling, is illustrated using distinct Oligo-Miocene reservoirs from offshore Congo. The final result is a deterministic succession of channels laterally stacked to reproduce the envelope and lateral migration observed on seismic. Associated heterogeneities are integrated into the reservoir models using transmissibility multipliers, calibrated to match DST results and then applied to the entire models. The resulting architecture respects the natural architecture of the complex and provides a better simulation of flow pathways than that achieved by random object modeling. In the context of a pre-development initial reservoir model, the main interest of this method is to provide much more realistic long-term recovery factors for such complex reservoirs.
Maximizing Oil Production and Increasing ESP Run Life in a Brownfield Using Real-Time ESP Monitoring and Optimization Software: Rockies Field Case Study
Authors: Ratcliff Dustin E. , Gomez Cesar , Cetkovic Ivan , Madogwe Odafe 
Published: September 2013

Abstract
Marathon Oil operates several brownfields in the Rockies, most of which are approaching a producing life of 100 years. Most of the fields are on waterflood, with 86% of the oil production coming from the artificial lift method of electrical submersible pumps (ESPs). This ESP lift method has helped maximize the production of recoverable oil in these fields, achieving higher drawdowns and larger fluid volume handling.
Prior to 2010, Marathon's 770 ESPs were operated with out downhole gauges or sensors and no ESP real time systems were in use. This made it difficult to properly monitor the well and the equipment, leading to improperly sized ESPs, limited artificial lift optimization and lost oil production. In 2010 Marathon began installing downhole sensors in all ESP wells that were pulled for either a failure or a workover and download the data into an ESP real-time monitoring, diagnosis and analysis software system.
At the time of this paper, Marathon has installed downhole sensors in 430 of the 770 ESP wells. All ESP wells are presently being monitored via the ESP real-time monitoring and analysis software. During this short period of real-time monitoring, Marathon has realized production gains of more than 700 barrels of oil per day (BOPD) in one of the fields.
This paper compares previous operations to the results and data from the installation and connection of downhole sensors to the real-time ESP monitoring program. Monitoring methodologies, analysis and proper ESP optimization are detailed in several case studies.
Drilling Rig Sensor Data Validation in the Presence of Real-Time Process Variations
Authors: Ambrus Adrian , Ashok Pradeepkumar , van Oort Eric 
Published: September 2013

Abstract
The safe and efficient construction of a well requires close attention to how the well and the rig equipment behave as the well is drilled. This primarily involves monitoring and correctly interpreting all the data collected at the rig site. In the past, this was primarily accomplished with an experienced drilling crew. While we still continue to use mostly antiquated rig sensors that were introduced decades ago, there has also been an "explosion" in the number of new advanced sensors used on a rig. The argument put forward for the additional sensors is that they increase safety and help reduce non-productive time and invisible lost time. Many of these new sensors provide data at high(er) sampling rates. This has made human monitoring of the data very difficult, if not impossible, and has led to a variety of event detection algorithms. The primary function of these event detection algorithms is to bring the driller's attention to anomalies in the system, based on data collected from all the rig sensors. However, the frequent occurrences of false and missed alarms, when using automated event detection software, can lead to significant downtime, and also reduce safety at the rig. One reason for these false alarms is bad data due to either sensor failure or data communication failure. Having sophisticated sensors, but not knowing whether the data can be trusted, defeats the very purpose of having additional sensors. This paper explores a methodology that can greatly reduce these false and missed alarms by validating the data coming from the sensors.
The data validation methodology described in this paper utilizes a Bayesian network model of the sensed parameters, to maximize the number of analytical redundancies among the parameters. Also, data is collected and aggregated from multiple sources within and outside the rig, such as the well plan, morning reports and real-time data, to obtain increased certainty in the prediction of sensor / process anomalies. The algorithm allows for the detection and isolation of sensor faults and process faults, and does not impose unrealistic assumptions of process invariance. For any type of drilling operation, the parameters in a drilling model are constantly changing. Here, we briefly discuss how the model can be updated in real-time, depending on whether the fault is in the sensor or in the process. The approach is very flexible and easily accommodates the widely varying number of sensors from rig to rig. The methodology can also be easily scaled to be applied on a small subsystem (top drive, hydraulic unit, etc.) or the entire rig (all surface and sub-surface sensors). The proposed methodology is applied on sample scenarios that are typical of the unconventional shale drilling operations conducted in North America.
Open Hole Packers Provide Zonal Isolation for High Pressure Acid Stimulation within a Chalk Reservoir
Authors: Hazel P. , Singh H. , Bårdsen J. , Vasques R. , Pearcy R. , Hannah N. 
Published: September 2013

Abstract
This paper overviews the design, development, qualification, and field trial deployment of a hydraulically expandable metal packer that enabled a cementless, zonal, high-pressure acid stimulation program to be accomplished.
Achieving effective zonal isolation within long reach horizontal wells using conventional means with cement is challenging to the industry. Achieving effective cement within long step outs is limited by the Equivalent Circulation Density (ECD) (impacted by fracture/pore pressure) or by the inability to achieve effective cement (i.e., without channels/micro annuli) simply due to the sheer length of the horizontal section of the well. Additional challenges are then imposed to achieve zonal isolation within unconventional reservoirs or wells that require high-pressure stimulation.
These challenges spurred the design for a metal expandable packer for use in a cementless completion, assembled on a full bore liner, and able to deliver a high annular Delta P seal in a worse case washed-out hole scenario.
Material selection to allow hydraulic expansion beyond the yield point of the expanding alloys (i.e., in the plastic region) is a key design consideration for maximizing the post-expansion strength of the expandable metal packer. Continual design, test, and result analysis enabled development of a unique, high-pressure seal between the metal expansion sleeve and the formation. The qualification process was based on the ISO 14310 V3 standard, the industry standard for testing and qualifying plugs and packers. This standard emulates the lifecycle of the packer during acid stimulation and later-life water management.
Field-proven zonal pressure isolation will be illustrated with real-time zonal pressure data from the field trial in an offshore field. The well will demonstrate cement-less liner completion efficiency with sixteen expandable metal packers to achieve five isolated, stimulated, and subsequently producing zones and three water shut-off zones.
In closing, the paper will summarize ongoing developments and how the open hole expandable metal packer is meeting the unique challenges of annular high-pressure containment. The many benefits to operators include fast setting under surface control with increased reliability and certainty for success.