bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design of a High-Pressure Research Flow Loop for the Experimental Investigation of Liquid Loading in Gas Wells
Authors: Fernandez J. , Falcone G. , Teodoriu C. 
Published: May 2009

Abstract
Existing models to predict and analyze liquid loading in gas wells are based on steady-state flow. Even when transient multiphase wellbore models are employed, steady-state or pseudo steady-state inflow performance relationships are used to characterize the reservoir. A more reliable approach consists of modeling the dynamics in the near-wellbore region with its transient boundary conditions for the wellbore. The development of new models to mimic the dynamic interaction between reservoir and wellbore requires a purpose-built flow loop. We have developed a design to construct such a facility.
This new facility will be the first to integrate pipe representing the wellbore with a porous medium that will fully mimic the formation surrounding the wellbore. This design will account not only for flow into the wellbore, but any reverse flow from the pipe into the medium.
We used integrated wellbore/reservoir system analysis to screen the parameters required to recreate liquid loading under laboratory conditions. Our results suggested using a compressed air system with a discharge pressure between 470 to 650 psi with gas rates of 400 to 650 scf/m along with water injected at a rate of 100 gpm. Once the range in operating conditions was defined, the equipment and mechanical components for the facility were selected and designed.
Our results showed that three reciprocating compressors working in parallel provide the smallest, most economic, and most flexible configuration for the TowerLab facility at Texas A&M University. The design of the pressure vessel hosting the porous medium will require a cylindrical body with top- and bottom-welded flathead covers with multiple openings to minimize weight. The required superficial velocities for air and water indicate that the system will need independent injection into the porous medium through two manifolds. Optimally, the system will use digital pressure gauges, coriolis or vortex technology to measure air flow and turbine meters for water flow.
The new facility will significantly improve our ability to mimic the physics of multiple phase flow for the development of liquid loading models and lead to better optimization of gas fields.
Successful Geosteering in Ecuador Using the Bright Spot Phenomenon from Deep Resistivity Images
Authors: Diaz M. , Iza A. , Rodas J. , Carrion C. , Manrique C. , Chemali R. , Pineda G. , Sandoval J. 
Published: May 2009

Abstract
The challenges presented by a field in Ecuador included placing the wells in the cleanest, most permeable portion of the reservoir, in the middle of the structure, without penetrating an overlaying kaolinitic bed or the caprock shale above the reservoir or penetrating the water bearing zone. These objectives could not be optimally achieved with traditional wellbore imaging sensors or with deep non-azimuthal wave resistivity. Wellbore imaging instruments identify the relative dip and azimuth of geological events intersecting the wellbore, but the information is clear only after leaving the reservoir. Non-azimuthal wave resistivity predicts the impending intersection with a reservoir boundary, but does not predict the azimuth of approach. In the first instance, a proper decision can be made only after exiting the reservoir; in the second instance, a proper decision requires other knowledge about the probable direction of the approaching boundary.
A newly deployed azimuthal deep resistivity while-drilling sensor produces a vast array of azimuthal measurements. When mapped into an image, deep resistivity behaves for the most part like traditional images in which "smiling" patterns indicate that the wellbore is going up stratigraphically and "frowning" patterns indicate that the wellbore is going down stratigraphically. One exception is the newly discovered phenomenon of the "bright spot" that appears when approaching a low resistivity shale or water bearing interval from a high resistivity reservoir. The bright spot clearly indicates an impending reservoir exit. Because it is keyed to the low side of the well, the bright spot indicates the direction of the required evasive action to remain within the desired interval. This visual indicator is complemented by a novel quantitative measurement, the Geosignal, which features a strong exponential dependence on the distance to the boundary of the reservoir. In the examples shown, the visual information from the bright spot is combined with the quantitative information from the Geosignal measurement to properly guide real-time geosteering decisions.
History Matching: Is it Necessary to Optimize?
Authors: Reis L. C. , dos Reis L. E. , da Silva L. C. , Becerra GG. 
Published: May 2009

Abstract
The oil industry has recently started to deal with probabilistic approach. Risk or uncertainty analysis have become part of the petroleum engineer's job. A set of curves with the associated probability instead of one deterministic curve is provided by the reservoir engineers. In order to use reliable curves, they shall have a history matched model. Assisted History Matching usually uses optimization processes. The aim of the optimization is to find the minimum of an objective function that represents the quality of the model. In this way, one can find the best model. The keyword is exactly "best". Why to make so much effort to find the best if we know that it is still far from the truth. Indeed, the concept of "best" is not suitable for the probabilistic approach.
This work discusses a functional history matching approach where an optimization process is no longer necessary. The functional history matching approach establishes that we have to look for a set of models that is above a level of quality according to the reservoir engineers. The method is quite simple. Among all possible models, we select those that have an objective function value under a pre-defined value.
In this approach the discussion lies not in the optimization issues like local minimum, convergence, and rapidity, but in how the quality of the model is measured. The objective function that usually measures the quality must be very well defined. Not only to better take into account the historical data but also to be suitable to the purpose of the study. Infill drilling and new secondary recovery systems would probably require different objective functions.
This work discusses the functional history matching approach coupled with uncertainty analysis. Usually very costly in terms of numerical simulations, uncertainty analysis can be done in this approach with simplified models (proxys). Different proxys were used - Surface Response Modeling (improved or not) and Artificial Neural Network. A simple synthetic case (PUNQ), and a real complex case (Brazilian onshore field) were used to illustrate the functional approach.
Inaccurate Gas Viscosity at HP/HT Conditions and its Effect on Unconventional Gas Reserves Estimation
Authors: Davani E. , Ling K. , Teodoriu C. , McCain W. D. , Falcone G. 
Published: May 2009

Abstract
Viscosity is one of the gas properties that is always uncertain at high-pressure and high-temperature (HPHT) conditions because no reliable correlation has been developed for HPHT and accurate measurement of gas viscosities at HPHT is difficult. However, the industry currently does not pay sufficient attention to the need for accurate gas viscosity values in HPHT gas fields’ development.
We show that small errors in gas viscosity affect the inflow performance relationship (IPR) curves and eventually change the reserves estimate for HPHT conditions in ways that can drastically influence production forecasting. A sensitivity analysis for a synthetic case at these conditions shows that a 1% error in gas viscosity measurement results in a 1% error in gas flowrate, which in a large scale of gas production may severely underestimate or overestimate recovery from an HPHT field. This linearity between gas viscosity and gas flowrate continues to ±10% errors.
An evaluation of gas viscosity correlations commonly used in the industry shows that none of them is reliable at HPHT conditions, mainly for two reasons: measured data are not available to confirm their consistency and they do not account for impurities in the gas.
Clearly, the industry needs accurate gas viscosity measurements and needs a new procedure to develop correlations based upon accurate HPHT gas viscosity data.
Slug Catcher Conceptual Design as Separator for Heavy Oil
Authors: Marquez J. , Manzanilla C. , Trujillo J. 
Published: May 2009

Abstract
The gas-liquid separation processes in the heavy and extra heavy oil fields are performed mainly with gravity conventional separators. However, the separation efficiency of these equipments depends on the operating conditions, the appropriate design and the properties of the fluids. Thus, in heavy and extra heavy oil fields, the separation efficiency is affected due to of the handle liquids of viscosity high, low pressures and low gas flow rate. Additionally, these conditions increase the probability of slug flow formation through pipelines that causes operational problems, mainly in the separation process.
In response to this situation, arises the need to design a gas-liquid separator able to handle viscous liquid, reduce the effects of slug flow and perform an efficient separation. In this sense, there are different technologies that can help to improve the gas-liquid separation, among them is found the finger type slug catcher. This technology is usually used in gas fields or light and medium oil fields as conditioner flow and slug flow mitigator. However, this paper has changed this focus for considering a design for heavy oil.
This paper presents an improvement in the methodology of Sarica et al. (1990) to predict the dimensions of finger type slug catcher to use in heavy oil fields. It is based on the effect from the transition of stratified flow to non-stratified flow when the liquid phase is viscous and only considers slug flow characteristics under normal flow. Based on the improvement the required diameter and length of the finger are determined.
The improvement is used to design a finger type slug catcher for heavy oil field conditions in Orinoco Belt and an economic comparison against conventional separators is presented. The comparison demonstrated that the finger type slug catcher designed with the proposed method is less expensive than the conventional separator.
A 3D Seismic Cube: What for?
Authors: Gambaretto W. , Peralta J. , Cortes G. , Suter A. , Dederle M. , Guarnizo E. Lozano 
Published: May 2009

Abstract
We have already more than X hundreds wells!!
We do not need a seismic cube now, do we?????
Who has not heard that kind of exclamation/question while working in oil/gas field development??
Casabe oil field was not the exception. Discovered in 1941, it's been in production since 1945. It cumulated 297 MM bbl of oil (October 2008) with more than 1100 wells drilled.
Since 2004, it's been operated by an Alliance formed by Ecopetrol and Schlumberger.
A 3D seismic cube was shot during the first half of 2007. By the middle of 2008, the seismic cube had been loaded and interpreted and by October of 2008 the production had been boosted more than 50%.
The reasons….?. Two main reasons: Seismic cube dataSelective string water injection
Of course: The second can not be properly implemented without the first.
By having a 3D seismic cube we were able to: Develop a precise and reliable structural modelDefine more accuratelly W/O contactsDefine more accuratelly the size of the fieldDesign more accurately well trajectoriesProperly place injector/producer wellsDesign more accurately the injection patternsEstimate reservoir quality: Seismic Inversion dataCompute gas reserves: Attribute-AVO analysisIncorporate undeveloped areasDiscover a new prospect
In other words it was possible to: Get more precise reserve picturesIncorporate: 10 % of the OOIP
Casabe Mature Field Revitalization through an Alliance: A Case Study of Multicompany and Multidiscipline Integration
Authors: Marquez L. , Elphick J. , Peralta J. , Amaya M. , Lozano E. 
Published: May 2009

Abstract
This paper summarizes the achievements of an alliance between Ecopetrol, S.A. and Schlumberger to revitalize the Casabe field, a mature field located in Colombia.
Challenges have been multifaceted in this mature complex field. Some relate to the heterogeneous nature of the reservoirs, limited sand continuity, unfavorable mobility for the waterflooding ongoing process, associated sand production, and wells lost due to collapses.
Parallel efforts on fast-track studies and field development planning (FDP) were performed. The FDP incorporates technology application such as: 3D seismicNew geological modelNew correlation in detailed scaleDrilling in fresh oil areas, infill, and new structuresSelective water injectionNew waterflood design and monitoringStrong increment of water injected by pattern.
From 2004 to 2008, the integrated project has increased the oil production from 5,200 BOPD to 11,900 BOPD with a reserves replacement ratio of more than 100% per year. All these factors provided extension to the life of this complex field while bringing additional financial benefits for the partners.
The article presents the FDP planning methodology, that overall proved to be useful and repeatable for other fields.
A New Approach to Improve Waterflood Predictions After Breakthrough: Field Case, Maracaibo Lake, Venezuela
Authors: Soto B. R. , Pérez V. O. , Soto O. D. A. , Hocol S. A. , Montiel E. 
Published: May 2009

Abstract
One of the most important parameters calculated by reservoir engineers in a waterflood project is the variation of average water saturation with time to estimate the recovery factor. For years, this average water saturation after breakthrough has been obtained by finding the intersection of the tangent to the fractional-flow water saturation curve, fw vs. Sw, at fw = 1.0. However, this technique is subject to errors because it is difficult to determine the exact point where the tangent to the fractional flow curve intersects the curve.
This paper discusses the development of a new function that matches with all fractional flow calculations from relative permeability displacement data to oil-water viscosity ratios. This new function has four parameters that vary according to the mobility ratio. The advantage of this new function is that its derivative can be used to calculate the average saturation after breakthrough, giving more accurate results when estimating waterflood predictions and the volume of oil displaced. If we use this new function technique along with rock type distribution, assigning a relative permeability curve to each rock type, it is possible to evaluate the possibility a waterflooding project with high certainty.
We present the procedure for determining the four parameters of this new general function and the advantages of its application through field examples from reservoirs in literature and from reservoirs in Maracaibo Lake, Venezuela.
Alternate Power and Energy Storage/Reuse for Drilling Rigs: Reduced Cost and Lower Emissions Provide Lower Footprint for Drilling Operations
Authors: Verma A. , Burnett D. 
Published: May 2009

Abstract
One of the major ways to reduce the footprint of drilling operations is to provide more efficient power sources for drilling operations. Rigs powered by the electrical grid can provide lower cost operations, emit fewer emissions, are quieter, and have a smaller surface footprint than conventional diesel powered drilling.
This paper describes a study to evaluate the feasibility of adopting technology to reduce the size of the power generating equipment on drilling rigs and to provide "peak shaving" energy through the new energy generating and energy storage devices such as flywheels.
An energy audit was conducted on a new generation light weight Huisman LOC 250 rig drilling in South Texas to gather comprehensive time stamped drilling data. A study of emissions while drilling operation was also conducted during the audit. The data was analyzed using MATLAB and compared to a theoretical energy audit. The study showed that it is possible to remove peaks of rig power requirement by a flywheel kinetic energy recovery and storage (KERS) system and that linking to the electrical grid would supply sufficient power to operate the rig normally. Both the link to the grid and the KERS system would fit within a standard ISO container.
A cost benefit analysis of the containerized system to transfer grid power to a rig, coupled with the KERS indicated that such a design had the potential to save more than $10,000 per week of drilling operations with significantly lower emissions, quieter operation, and smaller size well pad.
Economic Analysis Using a Real Option Model in an Exploratory Project
Authors: De Abreu C. C. , Cavalcante Filho J. A. 
Published: May 2009

Abstract
The Real option Valuation theory is based on the concepts of the options traded in stock markets applied to real projects, where those are considered options of investment. The methodology enables the valuation of a manager's flexibility to adapt and review his estimates for investment decisions if market or project's processes have any change. Real Option Valuation considers flexibility caused by uncertainties as a key point of an economic analysis of an investment.
This paper intends to develop a real option valuation model to be applied in investment opportunities where uncertainties related to the initial production rate and the decline rate are key variables, considering an exponential decline. We consider a scenario where we have an exploratory project with high leves of uncertainties regarding possible future production. Based on exploratory information about the field the company will decide if it will develop the reservoir or not. These uncertain variables are modeled by stochastic processes causing impact on the production of an oil field and in its economic returns as a result.
The model's main idea is the definition of a decision-making rule including the valuation of the flexibility from the possibility of delaying an investment in an oil field due to better geological information. We used a continuous time real option model to estimate the option value and investment trigger point and compared the results to estimates from evaluation using traditonal discounted cash flow economic analysis methodology.
The evaluation model is applied to a set of production curves based on real production data from a producing reservoir located in the Brazilian northeastern coast. Preliminary results show that the investment – rule is different from that of traditional NPV, that is, insvest as long as NPV &gt; 0. The methodology can be used as an additional economic analysis decision-making tool to help managers decide in an uncertain production environment. This model does not eliminate the traditional evaluation methodology.
An Integrated and Systematic Revitalization of a Mature Asset
Authors: Maldonado G. , Gomez U. , Degiorgis G. , McLeroy P. , Sharifi A. , Sharry J. , Chow C. 
Published: May 2009

Abstract
The Vizcacheras License in Mendoza Province, Argentina, is a complex multi-reservoir asset within YPF's mature asset portfolio. Facing a current recovery factor averaging 46+% between the producing reservoirs, YPF embarked on a program to enhance recovery and maximize asset value. Vizcacheras, discovered in 1962, stands with 400 wells in 2 structures with homogenous and heterogenous reservoirs and operated by 4 different organizations. Peak production was 38,000 bopd; currently producing 10,000 bopd with water cut of 97%. Beyond the geologic complexity, was the commercial challenge rejuvenating the field under mounting operating costs. YPF decided to respond by assessing: if the field had stranded value; the magnitude of stranded value; and, method(s) to deliver value. A multi-disciplined YPF and Arthur D. Little team was formed to assess the Vizcacheras license from subsurface through surface employing innovative technical systems analysis to build a risk-based field development plan.
The focus of revitalizing a mature field is to define a customized asset evaluation approach to quickly manage large amounts of data and identify key mechanisms for stranded value and value-added solutions, while minimizing costs. The team captured this through innovative systems planning and operation, displacing the traditional lab-to-field R&D search in that multiple options were generated from within functional technology contributions.
The result is convergence toward multiple enhanced recovery and operational changes that are anticipated to yield increased recoveries and more efficient management of the asset. Diagnostic analyses of production profiles from individual wells and patterns of wells identified zones of poor reservoir sweep and bypassed oil, guided by large-grid simulation models aimed to reduce risks. Uplift opportunities from pump optimization, infill drilling, injection and adjusted secondary recovery patterns were identified using a risk-based value analysis, with an anticipated increase in recoverable oil of 3%. EOR strategy work is currently underway in which YPF envisions up to three times the recent optimization results.
Use of a ground up approach to gather, quality check, and integrate data to build models of the geological framework and to conduct quantitative engineering analysis of the system's performance is showing added recovery benefits from the integrated workflow as it is implemented.