bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fluid Analysis and Sampling: The Next Big Step for Logging While Drilling Tools
Authors: Sanchez F. Galvan , Cartellieri A. , Pragt J. , Meister M. 
Published: April 2012

Abstract
The first formation testing tools were introduced as wireline tools in the 1950s. Since then, many technological steps were achieved, starting with simple sampling devices adding different measurement technologies in the 1980s up to formation pressure while drilling (FPWD) tools introduced to the field in 2000. Over the last 20 years wireline technology evolved towards high-quality single-phase sampling that also led to the development of the first formation sampling while drilling (FSWD) tools being introduced just over a year ago.
In this paper we present a new fluid analysis and sampling tool designed for logging while drilling (LWD) applications. As it is built on the widely proven FPWD technology, it includes all its functionality of optimized testing and seal control.
This service operates using a closed-loop control system, integrates real-time downhole analysis of the pressure data, and provides a repeat pressure test with an optimized rate control based on the in-situ derived mobility. This is made possible by the highly accurate pump control system employed. In addition to pressure and mobility capabilities the fluid analysis and sampling tool can analyze and obtain formation fluid samples. The new tool is equipped with high-power pump-out capabilities and highly sophisticated sensors to measure the optical refractive index, the sound speed, the density and the viscosity of the fluid. The innovative pump control prevents alteration of the fluid sample by avoiding pumping below the bubble point.
The tool employs the same sample tanks that are used in our wireline tools. The tanks are approved by the Department of Transportation (DOT) for direct transportation of a sample to a certified pressure-volume-temperature (PVT) lab without transferring the sample into another sample bottle. The tool can collect and preserve up to 16 single-phase samples at surface pressures up to 20,000 psi in a single run. It uses a nitrogen buffer system to ensure the suffienct pressure is applied to the sample to prevent alteration.
In this paper the capabilities of this new LWD fluid analysis and sampling tool and its first field application on a land rig in Oklahoma are be shown. The field results are compared with a wireline results run to prove the concept of shorter clean-up times while sampling soon after the formation is penetrated by the drill bit. An outlook will be given how to apply this new technology in future applications.
Successful Deployment of a New Generation of Progressive Cavity Pump in a High GOR Argentinian Heavy Oil Field
Authors: Zimmer L. , Young E. , Bertomeu F. 
Published: April 2012

Abstract
Following the study of Progressive Cavity Pump Technology's behavior in Multiphase conditions (SPE Paper 95272 -presented at the SPE ATCE 2005 in Dallas, TX, USA) and the subsequent development of the "New PCP" (SPE Paper 97833 - presented at the SPE ITOHOS 2005 in Calgary, AB, Canada), this paper presents an overview of a pilot project where the Hydraulic Regulated Progressive Cavity Pump (HR-PCP - new name of the technology) was deployed in an Argentinean Heavy Oilfield.

Application
Deployment of the HR-PCP Technology in a gassy heavy oil field with recurrent Artificial Lift System failures. Average GOR usually recorded around 600 m3/m3 with presence of CO2.
Conversions of 6 wells from conventional PCPs, Sucker Rod Pumps and natural flow to HR-PCP.

Results observations & Conclusions
The implementation of the first version of the HR-PCP technology led to mixed results. A second version was then deployed and led to successful results in terms of production, run life and overall operational costs.
The HR-PCP not only was able to provide a solution to the reliability issues. It proved to be able to handle extreme Gas Void Fraction values and reduce per well power consumption.
Key to the success of this pilot project was the interest brought by all companies involved (operator, manufacturer and distributor) creating a valuable teamwork in order to share point of views, data and field operation practices.
Further testing will determine if the HR-PCP will allow optimizing the field production by maximizing the drawdown.

Significance of Subject Matter
The HR-PCP technology is meant to better handle gas than the conventional PCP Systems, enabling not only to operate at higher GVF (up to 99% compared to usual maximum of 30 to 40%), but for a much longer time and with no need of downhole gas separation technology.
The HR-PCP Technology targets include re-activation of wells considered uneconomic in mature fields, conversion of inefficient gas lift systems, increase run life in ageing or naturally gassy oil wells, increase reliability of artificial lift systems in gas well dewatering as well as allowing production from complex heavy/waxy/gassy oil wells, eliminating the need for gas anchors/separators.
An Integrated Case Study of Improve Oil Pay Evaluation in Shaly, Laminated, Low Mobility Reservoirs Using Wireline Cased Hole Dual Packer and Production Test
Authors: Mas C. , Yaxley L. , Ardila M. , Ayan C. , Tanuwidjaja V. Indrayanti 
Published: April 2012

Abstract
The subject of the case study is a recently discovered oil and gas accumulation characterized by laminated, shaly sandstones with high apparent water saturation. Conventional openhole log data was inconclusive in identifying hydrocarbon type and net hydrocarbon pay zones. Moreover, reservoir complexity, low mobility, and inadequate differentiation of oil versus gas pay made it unlikely that a conventional production testing program would be successful and cost effective. However, reservoir fluid identification and pressure measurements were critical for resolving key uncertainties and guiding decision making for future appraisal and development.
Cased-hole wireline formation testing was used to better determine reservoir fluid type and productivity in selected intervals so as to differentiate oil pay from gas pay and net pay limits. A total of 30 dual packer stations were conducted in cased hole. The test results were used to choose the intervals, methodology, and equipment for subsequent production tests, which successfully proved the existence of three separate oil reservoirs and demonstrated commercial production rates.
Wettability Modifier Field Trial in a Sandstone Condensate System: Facts and Gaps of a Promising Technology
Authors: Restrepo A. , Ocampo A. , Arenas M. , Rendon N. , Osorio R. , Reyes D. 
Published: April 2012

Abstract
Deliverability of gas and liquid hydrocarbons in retrograde condensate systems is highly affected by factors related to both reservoir characteristics and operative variables. It is well documented that pressure depletion coupled with tight petrophysical environments can lead to severe PI decrease due to liquid accumulation initially in the near wellbore area and then in the whole reservoir. Conventional approaches for condensate blockage removal have included the injection of low interfacial tension systems and alcohol blends to promote capillary forces minimization up to levels at which liquid bank gets remobilized. This type of solutions though, can be durability limited as liquid will reform once chemicals leave treated area. This condition become even more critical when static reservoir pressure gets below dew point as liquids from non treated zone will rapidly imbibe into the treated zone decreasing durability even further.
The present work documents a field trial of a fluoro polymer technology aimed on Kro and Krg enhancement by rock wettability modification. This technique, as opposed to conventional chemistries working at the fluid-fluid interaction level, is aimed on altering rock's original wettability. The objective is to promote a neutral wettability condition to minimize capillary effects driven by the contact angle according to LaPlace equation (fig 1).
Through a "facts and gaps analysis", a set of root causes are presented to explain the high PI improvement (–50%) but limited durability observed at field scale. Uncertainties on original rock wettability condition, water saturation profile in the near wellbore, deployment technique effectiveness and chemical properties of size and adsorption are all included in the root cause analysis. Data from pre job coreflood tests, pumping variables behavior and backflowed samples chemical analysis are also incorporated to the exercise. A final set of recommendations derived from the f&g analysis are to be included in further trials of the wettability modification technology where heterogeneous sandstone, compositional condensate environments are present.
An Innovative Solution to Optimizing Production in Naturally Fractured Carbonate Reservoirs in Southern Mexico
Authors: Quevedo M. , Tellez F. , Resendiz T. , Bueno O. Jimenez , Ramirez G. 
Published: April 2012

Abstract
The results of stimulation treatments in southern Mexico's carbonate reservoirs have been significantly improved using a new fiber-assisted, self-diverting acid system. These reservoirs are thick, deep, and hot. Depths are usually greater than 15,000 feet, bottomhole temperatures reach up to 350°F, and permeabilities range from 1 to 1000 mD within the same interval. Wells are typically completed with multiple perforated intervals. In the past, high-viscosity diverting fluids have been used to improve zonal coverage during stimulation treatments. Despite repeated treatments during the life of the well, in many cases, post-treatment logs show that the treatment was not effectively diverted to lower permeability, less productive intervals. To overcome these challenges, we introduced an innovative degradable diverting acid system combining the properties of viscoelastic diverting acid (solid-free) and degradable fibers to southern Mexico. This, combined with a rigorous candidate selection process, resulted in improved zonal coverage, increased oil production, and higher ultimate reserve recovery.
Maximizing oil production using this diverter system requires a detailed understanding of the petrophysical properties of the reservoir and production history. This information helps determine treatment volumes and the volume and number of diverter stages. Wells with the highest permeability contrast are often the best candidates. In many cases, producing from natural fractures depends on correctly determining the number and volume of the diverter stages. The experienced gained from treating more than 10 wells has resulted in the development of clear guidelines with respect to the treating fluid, volume, and number of diverter stages. On average, the guidelines have resulted production increases of 1,500 BOPD. By applying the treatment guidelines with an effective diverter fluid, operators can significantly increase oil and gas production in previously stimulated or new wells within naturally fractured carbonate reservoirs.
Minimum Flowrate to Unload Gas Wells: Dynamic Multiphase Modeling to Validate Existing Correlations
Authors: Daas M. , Golczynski T. , Harry J. 
Published: April 2012

Abstract
The Turner model is widely used in industry to estimate critical gas velocity to flow a gas well and unload its liquid content under steady state conditions. The Zhou model introduced improvements to the Turner model by taking into account the influence of total Liquid (condensate and water) to Gas Ratio (LGR) on critical gas velocity. While fairly acceptable at low LGR, current models do not address the impact of liquid holdup on wellhead flowing conditions and subsequent changes in critical gas unloading rates. Multiphase modeling is used in this study to validate the applicability of current models at various wellbore conditions and LGR.
This study finds important applications in offshore and onshore gas field developments because it provides moe reliable assessment especially for gas fields in the depletion phase, or when liquid breakthrough occurs resulting in high LGR.
Dynamic simulations indicate that at low to moderate LGR existing models under predict critical gas flowrate because they under estimate critical velocity, especially at high wellhead pressures, and don't take into account the impact of increasing liquid holdup on gas flowrate. Moreover, an inversion in critical flowrate occurs at very high LGR because the film holdup is sufficient to restrict the flow of gas and offsets any increase in critical velocity at such high LGR. The onset of liquid loading (well choking) is associated with the transition from annular to churn/slug flow. This is well demonstrated from the calculated trends of entrained droplet holdup.
The significance of the current work to our understanding of critical flow in gas wells is illustrated by utilizing a multiphase simulator to better characterize the impact of entrained droplet and film holdup on critical flowrate and by predicting the inversion in critical gas flowrate at high LGR. The results of this study provide an enhanced understanding of well loading during all development phases and various production conditions to evaluate the applicability and accuracy of widely used models in a broad range of well conditions and liquid loads.
Production Forecasting for Shale Gas Exploration Prospects Based on Statistical Analysis and Reservoir Simulation
Authors: Morales-German G. , Navarro-Rosales R. , Dubost F. Xavier 
Published: April 2012

Abstract
Shale gas exploration and production is still in its infancy. Information is scarce and flow monitoring is usually absent, but many studies aiming to understand gas shale reservoir behavior and to optimize its exploitation are now being developed. However, the understanding of fluid flow and transportation mechanisms in shales, given their micropore particular matrix structure coupled to induced fractures, is still under debate.
Several shale gas exploration projects are currently underway in diverse regions of Europe and Africa. The current lack of understanding of the main elements controlling well productivity, and the limitations of the available tools to correctly characterize the reservoir and forecast production from this type of well, make it difficult to predict the likely commercial value of a project. This value is controlled by drilling costs and the associated number of wells to develop a play, and the production returns that each of these wells may deliver.
The purpose of the work presented in this paper was to generate, based on statistical analysis of major shale gas basins in the USA, a synthetic reservoir simulation model that can represent shale gas wells and be used for forecasting purposes in exploration areas with limited available information. Such a prediction is mainly based on the accurate identification of parameters that have the greatest impact on production, either reservoir parameters or operational/controlled parameters, so that the production profiles may be predicted and controlled parameters optimized.
Integration of Surface and Reservoir Modeling for Steam Assisted Gravity Drainage on the Bare Field in Eastern Venezuela
Authors: Ruiz R. , Nuñez J. , Martinez A. , Alvarez A. 
Published: April 2012

Abstract
The efficient and economic recovery of heavy oil and bitumen is a mayor technical challenge due to their high viscosity. In the Orinoco Oil Belt, due to the high viscosity, different thicknesses and heterogeneities found, thermal recovery processes have demonstrated to be the best alternative for the enhancement and acceleration of heavy oil recovery. Bare Field, with an average API gravity of 10°, is among the fields of the Orinoco Oil Belt where thermal recovery has been applied through the implementation of Cyclic Steam Injection in horizontal wells, with substantial productivity increase. This led to the introduction of the first SAGD (Steam Assisted Gravity Drainage) pilot project on the Orinoco Oil Belt, on the Bare Field, this pilot test is in operation from 2009, and the recovery factor of the area affected by the steam is estimated to increase from 14 to 60 %
The location and design of these SAGD wells was accomplished using independents models for reservoir, well and surface, creating a production scenario without taking into account the interaction between models. A dynamic coupling of the reservoir simulation model with the well and surface models allows the consideration of more realistic boundary conditions. In this sense, an integrated model was developed in the present work, allowing the dynamic evaluation of the entire system helping to understand the energy consumption along the system to improve the recovery method performance.
To develop this model, a dynamic thermal reservoir model was created from an existing static model of the reservoir. Once the reservoir model was able to reproduce the flow rates, pressure and temperature with acceptable accuracy compared to the real history data, the next step was the elaboration of well models. The reservoir and well models were coupled in one model to evaluate the advantages of use integrated models for the evaluation of the energetic efficiency of SAGD projects.
Estimation Coalbed Methane Content from Elemental Analysis for "Los Cuervos" Formations High Volatile Bituminous C Coals Applying Nonparametric Regression Techniques
Authors: Rodríguez S. , Navas G. , Gómez A. 
Published: April 2012

Abstract
Unconventional gas exploration and development is the new challenge that faces the Colombian energy industry, and understanding of the reservoirs is the first step to achieve the goal of increasing gas reserves. Coalbed Methane (CBM) has become an important resource given that Colombia holds the largest coal reserves in Latin America.
Exploration of CBM began in 2008 with characterization of coal reservoirs, gas content, and storage capacity of four coal bearing formations in the main Colombian basins. In addition, the coals were assessed using techniques such as proximal and ultimate analysis, Rock-Eval pyrolysis, organic petrography, gas chromatography, isotopic analysis and desorption tests.
From the four basins evaluated, this article will be focused in "Los Cuervos" Formation where four stratigraphic wells were drilled. Based on ultimate analysis and gas desorption measurements of cores, a mathematical model for estimating gas content was developed. The gas content showed excellent correlation and statistical significance with depth, total carbon and moisture percentage. 53 samples, classified as High Volatile Bituminous C using heating value from proximate analysis, were included in this study. Non parametric regression techniques based on statistical and optimization theory were applied to find the best correlation for predicting gas content. The equation set was generated with Grace98® software applying the ACE method. The non parametric model obtained explains the 92.5% variability of gas content and makes predictions with exactitude of 91.8%. The average percent deviation between experimental and calculated gas content was 7%, indicating good fitting between data and the proposed model. Based on the Anderson Darling test and residual plots, the errors generated from prediction were found to be randomly dispersed without any pattern. The obtained results showed that non parametric techniques were more efficient to predict gas content than conventional multiple regression. It was also found that there is not a kind of "universal correlation" but specific basin correlations since the gas content depends on geologic characteristics.
Mature Carbonate Heavy Oil Field Exploitation Strategies: The Cretaceous Ku Field, Mexico
Authors: Pérez-Martínez E. , Rojas-Figueroa A. 
Published: April 2012

Abstract
This paper aims to present the strategy for future exploitation of the Ku oil field, based on its historical behavior of pressure-injection-production profiles and the advance of gas-oil and oil-water contacts.
The production performance of all wells in Ku oil field was analyzed in order to evaluate the gas and water breakthrough and production.
A pressure maintenance program was started in 2009 by injecting nitrogen at a rate of 160 MMsfc/D, which reduced the pressure decline from 4.45 to 1.36 kg/cm2 per year. At the end of 2011, the nitrogen injection rate was increased to 250 MMscf/D in Ku field in order to maintain reservoir pressure and minimize advance of the OWC (oil-water contact), which is estimated at 3,140 vertical meters subsea (vmss). On the other hand, the GOC (gas-oil contact) continues to advance at a rate of 25 m/year. To maintain production, a staggered workover schedule is utilized to open new producer intervals in every well where the gas cap approaches.
Ku is one of the offshore oil fields located in the Ku-Maloob-Zaap Asset. It produces mainly from naturally fractured carbonates in the Upper Cretaceous (UC), Middle Cretaceous (MC) and Lower Cretaceous (LC) formations. In addition to high net pay thickness and structural relief, UC rocks have a very high permeability, which ranges between 4 and 9 Darcies, because of high fracture density. This condition gives the formation a thief zone characteristic during drilling, cementing and completion jobs. In fact, during cementing of the last casing pipe on many wells, most or all cement slurry volumes are lost to the formation, creating an unrestricted channel to flow and thus an increased tendency towards water coning.
The remaining oil reserves volume in Ku oil field will be recovered from the oil column located between the contacts. Therefore, it is necessary to understand the production performance under these conditions in order to establish the optimal operative ranges under which wells will be producing. The water coning and fluids channeling effects depend upon the rock – fluids properties, well geometry and design, and, finally, the production conditions under which the wells will be operated.
A New Reservoir Classification Based on Pore Types Improves Characterization
Authors: Rodolfo Soto B. , Martin Cintia , Pérez Orlando , Arteaga Duarry 
Published: April 2012

Abstract
In the past, only four types of reservoirs were defined to characterize matrix and fracture systems. These definitions based on matrix and fracture systems do not cover all the pore systems present in the real world because a great number of reservoir systems are made up of different lithologies and pore types. The pore types could be matrix, fractures, or vugs or combinations of these. One of the potential problems is that engineers have simplified that complex problem and therefore have erroneously produced the reservoirs. If a complete classification were available in the literature, more effort would have been made to recognize all the pore types present in a specific reservoir for better characterization and production.
This paper discusses a new methodology to classify all kind of reservoirs in the real world: fracture, matrix, vugs, or combinations of those. We have developed membership functions using fuzzy logic concepts for the cementation factor m variable. We have identified at least five types of reservoirs according to pore types.
All types of unconventional or conventional reservoirs are represented in this new classification system. We used core data from Southern Vietnam, Libya, the United States, Argentina, Iran, Iraq, Saudi Arabia, Colombia, and Venezuela to validate our new classification, and we are certain that it will be of great help to the engineers. Better understanding of the behavior of a specific reservoir will help increase the production and the recovery factor.
We also discuss how to increase the oil or gas production as a reservoir moves from one class to another as result of hydraulic fracturing.