bluuebunny/crossref_metadata_2025_split huggingface dataset:
Dynamic Filtration Properties of Clay Based Drilling Muds under Elevated Temperatures
Authors: Osgouei A. E. , Ozyurtkan M. H. , Altun G.. , Dilsiz E. A. 
Published: December 2012

Abstract
Static filtration of drilling fluids has long been recognized as an important parameter for drilling operations. Since the standard laboratory testing procedures only consider static conditions, the filtration and cake properties under continuous circulation and dynamic borehole conditions are not usually well determined. Therefore, the measurement of dynamic filtration is particularly important in order to mimic actual downhole conditions.
An experimental study has been carried out by the ITU/PNGE research group to characterize the dynamic filtration properties of clay based drilling fluids. This study is an impressive attempt to figure out the dynamic filtration phenomena of clay based muds. The experimental results obtained from a dynamic filtration apparatus (Fann Model 90) are reported in this study.
Bentonite and sepiolite clays based muds formulated with commercial additives have been investigated throughout the study. Numerous dynamic filtration histories with test duration of 45 to 60 minutes at temperature conditions ranging from 150 to 400 °F, and a differential pressure of 100 psi have been applied to muds. Three key parameters namely spurt loss volume, dynamic filtration rate (DFR), and cake deposition index (CDI) have been determined to characterize the dynamic filtration properties of mud samples.
Results have revealed that bentonite based muds have better dynamic filtration properties than those of sepiolite muds at temperatures up to 250 °F. However, they have lost their stability over 250 °F. Furthermore, formulated sepiolite based muds have remarkable dynamic filtration rates and cake depositions above 300 °F. To sum up, the experimental results of this study point out that sepiolite based muds might be a good alternative to drill wells experiencing high temperatures, particularly in deep oil, gas and geothermal wells.
Evaluation of the Effect of Asphaltene Deposition in the Reservoir for the Development of the Magwa Marrat Reservoir
Authors: Al-Qattan A.. , Blunt M. J. , Gharbi O.. , Badamchizadeh A.. , Al-Kanderi J. M. , Al-Jadi M.. , Dashti H. H. , Chimmalgi V.. , Bond D. J. , Skoreyko F.. 
Published: December 2012

Abstract
The Magwa Marrat reservoir was discovered in the mid-1980s and has been produced to date under primary depletion. Reservoir pressure has declined and is approaching the asphaltene onset pressure (AOP). A water flood is being planned and a decision needs to be taken as to the appropriate reservoir operating pressure. In particular the merits of operating the reservoir at pressures above and below the AOP need to be assessed.
Some of the issues related to this decision relate to the effects of asphaltene deposition in the reservoir. Two effects have been evaluated. Firstly the effect of in-situ deposition of asphaltene on wettability and the influence that this may have on water-flood recovery has been investigated using pore scale network modes. Models were constructed and calibrated to available high pressure mercury capillary pressure data and to relative permeability data from reservoir condition core floods. The changes to relative permeability characteristics that would result from the reservoir becoming substantially more oil-wet have been evaluated. Based on this there seems to be a very limited scope for poorer water flood performance at pressures below AOP.
Secondly the scope for impaired well performance has been evaluated. This has been done using a field trial where a well was produced at pressures above and substantially below AOP and pressure transient data were used to estimate near wellbore damage "skin". Also compositional simulation has been used to estimate near wellbore deposition effects. This has involved developing an equation of state model and identifying, using computer assisted history matching, a range of parameters that could be consistent with core flood experiments of asphaltene deposition. Results of simulation using these parameters are compared with field observation and used to predict the range of possible future well productivity decline.
Overall this work allows an evaluation of the preferred operating pressure, which can drop below the AOP, resulting in lower operating costs and higher final recovery without substantial impairment to either water-flood efficiency or well productivity.
Field Treatment to Stimulate a Deep, Sour, Tight Gas Well using a New, Low Corrosive and Environmentally Friendly Fluid
Authors: Nasr-El-Din H. A. , de Wolf C. A. , Stanitzek T.. , Alex A.. , Gerdes S.. , Lummer N. R. 
Published: December 2012

Abstract
Matrix acidizing of high temperature gas wells is a difficult task, especially if these wells are sour or if they are completed with high chrome content tubulars. These harsh conditions require high loadings of corrosion inhibitors and intensifiers in addition to hydrogen sulfide scavengers and iron control agents. Selection of these chemicals to meet the strict environmental regulations adds to the difficulty in dealing with such wells. Recently, a new environmentally friendly chelating agent, glutamic acid -diacetic acid (GLDA), has been developed and extensively tested for carbonate and sandstone formations. Significant permeability improvements have been shown in previous papers over a wide range of conditions. In this paper we evaluate the results of the first field application of this chelating agent to acidize a sour, high temperature, tight gas well completed with high chrome content tubulars.
Extensive laboratory studies were conducted before the treatment, including: corrosion tests, core flood experiments, compatibility tests with reservoir fluids, and reaction rate measurements using a rotating disk apparatus. The treatment started by pumping a preflush of mutual solvent and water wetting surfactant, followed by the main stage consisting of 20 wt% GLDA with a low concentration of a proper corrosion inhibitor. Following the treatment, the well was put on production, and samples of flow back fluids were collected. The concentrations of various ions were determined using ICP. Various analytical techniques were used to determine the concentration of GLDA and other organic compounds in the flow back samples.
The treatment was applied in the field without encountering any operational problems. A significant increase in gas production that exceeded operator expectations was achieved. Unlike previous treatments where HCl or other chelates were used, the concentrations of iron, chrome, nickel, and molybdenum in the flow back samples were negligible, confirming low corrosion of well tubulars. Improved productivity and longer term performance results confirm the effectiveness of the new chelate as a versatile stimulation fluid.
Reservoir Characterization Using Wellbore Storage Dominated Flow
Authors: Al Rbeawi Salam , Tiab D.. 
Published: December 2012

Abstract
The reliability of the estimated parameters in well test analysis depends on the accuracy of measured data. Early time data are usually controlled by the wellbore storage effect. However, this effect may last for the pseudo-radial flow or the boundary dominated flow. Eliminating this effect is an option for restoring the real data. Using the data with this effect is another option that can be used successfully for reservoir characterization.
This paper introduces a new technique for interpreting the pressure behavior of horizontal wells and fractured formations with wellbore storage. A new analytical model describes the early time data has been derived for both horizontal wells and horizontal wells intersecting multiple hydraulic fractures. Several models for the relationships of the peak points with the pressure, pressure derivative and time have been proposed in this study for different wellbore storage coefficients. A complete set of type curves has been included for different wellbore lengths, skin factors and wellbore storage coefficients. The study has shown that early radial flow for short to moderate horizontal wells is the most affected flow regime by the wellbore storage. For long horizontal wells, the early linear flow is the most affected flow regime by the wellbore storage effect.
The most important finding in this study is the ability to run a short test and use the early time data only for characterizing the formation. This means there is no need to run a long time test to reach the pseudo-steady state. Therefore, from the wellbore storage dominated flow, the early radial and pseudo-radial flow can be established for horizontal wells and hydraulic fractured formations. A step-by-step procedure for analyzing pressure tests using the analytical models (TDS) and the type curves is also included in this paper for several numerical examples.
A High Angle and Horizontal Well Interpretation Toolkit for Quantitative Formation Evaluation and Reservoir Characterization
Authors: Zhou JinJuan , Guo Pingjun , Mardon Duncan , Passey Quinn , Mendoza Alberto , Gaillot Philippe , Wertanen Scott , Yin Hezhu , Fitz Dale , Nicosia Wayne 
Published: December 2012

AbstractOver last several years, the ability to perform accurate, quantitative formation evaluation in high-angle and horizontal (HA/HZ) wells has been increasingly recognized as a high priority, unsatisfied need within the formation evaluation (FE) community. The industry has realized that the ability to drill extended reach wells has surpassed the ability to evaluate them. Well logs are often underutilized for geologic modeling and assessment applications due to lack of confidence in petrophysical analysis results.In this paper, we introduce a state-of-art formation evaluation toolkit specifically developed for quantitative interpretation of high angle and horizontal well logs. Starting with wellbore images and standard triple-combo field logs, the workflow consists of: 1) three-dimensional (3D) and two-dimensional (2D) display modules for well path, wellbore images logs, scalar logs and dips to quality control (QC) the data; 2) a comprehensive image analysis module combined with log analysis to build a 3D geometrical earth model; 3) a depth coherence processing (DCP) module to effectively correct recorded borehole images of different logging tool sensors with different depths of investigation (DOI) back to borehole size (BS); 4) a 3D joint inversion module to accurately model and interpret gamma ray (GR), neutron, density, and resistivity logs, to build a common petrophysical earth model; and 5) an output module in which the common earth model is populated with bedding geometries and petrophysical property distributions.The advanced formation evaluation toolkit described in this paper enables geoscientists to realize much more value than ever before from high-angle and horizontal well data, especially in thinly bedded reservoirs. The detailed description of the internal architecture and lateral petrophysical characterization of the reservoirs are essential for understanding stratigraphy and conditioning geological models. The improved estimations of the petrophysical properties yield more accurate estimates of reserves in place.
Heavy Oil Viscosity and Density Prediction at Normal and Elevated Temperatures
Authors: Alomair Osamah , Ali Mohammad A.J. , Alkoriem Abullhaq , Hamed Mohamed 
Published: December 2012

Abstract
Viscosity and Density are important physical parameter of crude oil, closely related with the whole processes of production and transportation, and are very essential properties to the process design and petroleum industries simulation. As viscosity increases, a conventional measurement becomes progressively less accurate and more difficult to obtain. According to the literature survey, most published correlations that are used to predict density and viscosity of heavy crude oil are limited to certain temperatures, API values, and viscosity ranges. The objective of present work is to propose accurate models that can successfully predict two important fluid properties, viscosity and density covering a wide range of temperatures, API, and viscosities. Viscosity and density of more than 30 heavy oil samples of different API gravities collected from different oilfield were measured at temperature range 15°C to 160°C (60°F to 320°F), and the results were used to ensure the capability of proposed and published correlations to predict the experimental viscosity and density data. The proposed correlation can be summarized in two stages. The first step was to predict the heavy oil density from API and temperature for different crudes. The predicted values of the densities were used in the second step to develop the viscosity correlation model. A comparison of the predicted and actual viscosities data, concluded that the proposed model has successfully predict all data with average relative errors of less than 12% and with the correlation coefficient R2 of 0.97, and 0.92 at normal and high temperatures respectively. Meanwhile, the results of most of the available models has an average relative error above 40%, with R2 values between 0.19 to 0.95. These comparisons were made as a quality control to confirm the reliability of the proposed model to predict density and viscosity values of heavy crudes when compared with other models.
Unconventional Use of Production Logging Technology
Authors: Chaudhary S.. , Murty M. S. , Bora S.. , Chandra Y.. , Singh P. P. , Pandey R. K. , Bhatt U. C. , Verma V.. , Ogra K.. , Pandey A.. , Gupta S.. , Sinha R.. 
Published: December 2012

Abstract
Production logging has been traditionally used for zonal quantification of layers for identification of most obvious workover for water shut off, acid wash or reperforation candidate identification. The basic sensors help in making some of the critical decisions for immediate gain in oil production or reduction in water cut. However, this technology can be used in a non standard format for various purposes including multilayer testing to obtain layer wise permeability and skin factor using pressure and flow rate transient data acquired with production logging tools. This is very crucial and complements the present wellbore flow phenomenon to better understand relative zonal performance of well at any stage of its production. In addition, production logging along with the pulsed neutron technique is very crucial to evaluate the complete wellbore phenomenon, understand some of the behind the production string fluid flow behaviors. Another major concern in low flow rate wells is recirculation, causing fall back of heavier water phase while lighter phase like oil and gas move upwards. This well bore phenomenon renders the quantification from production logging string, and this in extension also prevents any comprehensive workover decisions on the well because of the risk involved. Oil rate computation from hydrocarbon bubble rates becomes very critical in such scenarios to bring out the most optimal results and enhance confidence in workover decisions. Another key concern in any reservoir is to evaluate the productivity Index; this is even more critical once the field is on production. It is essential to determine the performance of various commingled layers and reform the Injector producer strategy for pressure support or immediate workover. Selective Inflow performance is a technique used to identify the Productivity index of various layers in a commingled situation. This paper elaborates on various non conventional uses of production logging from the western offshore India.
Wettability Alteration of Carbonates by Optimizing the Brine and Surfactant Composition
Authors: Martavaltzi Christina , Dakik Ahmad , Agrawal Shubham , Gupta Anuj 
Published: December 2012

AbstractIt is well known that the majority of carbonate reservoirs are neutral to oil-wet. This leads to much lower oil recovery during waterflooding since there is no spontaneous imbibition of water in heterogeneous reservoir displacement. It has been verified by a number of researchers that Adjustment of ion concentration in brine solutions, or adding surfactant solutions can enhance the oil recovery by altering the wettability. In the published literature, contact angle studies usually refer to measurement on calcite crystals and there are no results for the contact angle of carbonate porous media representative of reservoir rocks. Moreover, there are few studies on the effect of non-ionic surfactants, compared to those for ionic surfactants. Understanding the effect of various ions and their concentration in the injection brine on the wettability of the Limestone outcrop core samples is the first step for tailoring of the optimum injection brine. This will be followed by a study of the effect of surfactant on the wettability of calcite crystal samples. The evaluation of the results may provide guidelines for the design of injection brines for efficient enhanced oil recovery from carbonate reservoirs.In this work, a procedure is established for the measurement of the contact angle on limestone outcrop core samples. Results showed that, at atmospheric conditions, low salinity CaCl2 solution induced the most significant improvement on the wettability of the outcrop sample. Moreover, among all the non-ionic surfactants studied, only the presence of the two first members of the 15S analogous series might lead to a slight decrease of the contact angle.
History Matching Saturation and Temperature Fronts with Adjustments of Petro-Physical Properties; SAGD Case Study
Authors: Mirzabozorg Arash , Nghiem Long , Chen Zhangxing , Yang Chaodong , Hajizadeh Yasin 
Published: December 2012

Abstract
History matching of reservoir flow models based only on production data may not reveal deficiencies that affect future predictions. Incorporating saturation and temperature profile data that come from 4D seismic surveys in the history matching process can reduce the uncertainty of reservoir models for the prediction stage. We constructed a field reservoir model from which production history, saturation and temperature profile history were obtained. We started the history matching process with a base reservoir model, the petro-physical properties of which were substantially different than those of the field reservoir model. We propose a new methodology for matching the fluid and temperature profiles by adjusting reservoir petro-physical properties. In this methodology, some grid blocks in a reservoir model were selected judiciously to capture the overall saturation and temperature distribution profiles. In addition to well production data, we included the saturation and temperature profiles at these grid blocks as extra objective functions during the history matching process. The DECE optimization is used to reduce the objective function. We applied this method in a Steam Assisted Gravity Drainage (SAGD) process and matched the saturation and temperature profiles with an average error of less than 2%.
An Integrated Approach to Designing an Offshore Heavy Oil Well Test - North Sea Example
Authors: Akuanyionwu Obinna , Shumakov Yakov 
Published: December 2012

AbstractOffshore production of heavy oil can be challenging due largely to adverse fluid properties, sand production and flow assurance concerns. Recent technology advancements effectively driving management of these challenges and government support through tax relief have significantly contributed to the increased appraisal activity over the last several years in the North Sea heavy oil fields. Application of appropriate technologies and techniques has always been of paramount importance for acquiring high quality information throughout welltest for reservoir characterization at appraisal stage of the fields. It also provides high level of confidence in technology and"proof of concept" prior to further application in a full field development at investment intensive offshore operating environment.This paper describes an integrated approach in analytical modeling and design developed and applied in the planning of flow test in a number of North Sea heavy oil fields. This includes a comprehensive pre-evaluation of well productivity, PVT properties modeling as well as design and selection of appropriate artificial lift method. A series of technical solutions considered relevant in relation to enhancing the low flowing well head temperature conditions, typically observed during the cold heavy oil production offshore and often leading to operational constraints on fluid handling capabilities is also discussed. Additionally, a probablistic approach considering base case, low and high case scenarios has been developed and implemented as part of the evaluation process, given the limited amount of available information and high level of uncertainties.The study demonstrates the benefits of applying analytical techniques for uncertainties handling during flow test planning and thereby enabling accentuation of potential issues, properly planning for mitigation actions and predicting the entire flow test sequence. Finally the study underlines some important guidelines pertaining to planning for further appraisal and development of new heavy oil fields.
Innovative In-house Geosteering Utilizes Gas-While-Drilling Data for Deep Jurassic High Angle Well Placement
Authors: Al-Shamali Adnan , Verma Naveen K. , Jha Bhawesh Chandra , Estarabadi Javad , Al-Khamees Waleed 
Published: December 2012

Abstract
The directional drilling companies in oil industry usually provide well placement services using proprietary geosteering software that utilize conventional Logging-While-Drilling (LWD) data. Usually online access to the recorded logs is available to end users, but often very limited capability exists within the oil companies to test geosteering interpretations and advise. Present paper shares the case studies of some wells in which Gas-While-Drilling (GWD) data was used in conjunction with the LWD data for well placement. Furthermore, the Geosteering Module of a third party 3D Geological modeling software was used independently within the West Kuwait Fields Development group of KOC for well placement.
Well D-08 was drilled as vertical producer in a West Kuwait Marrat carbonate reservoir, produced economic quantities of oil during initial testing, but it started cutting high amount of water due to the effect of a fault. Therefore, the well was re-entered and sidetracked at a high angle, away from the fault. Similarly, the U-73 vertical well which encountered poor reservoir facies on flank of the field, was re-entered for productivity enhancement into a thin porous reservoir layer as horizontal sidetrack towards the crest. Both these wells were monitored and geosteered in near real-time using a geosteering software module which combines the overall structural framework provided by 3D geological model, along with the well log responses characteristics from offset wells, to produce a detailed pre-drill model for Geosteering. This is achieved by forward modeling to predict changes in log characters along the planned wellbore profile. The results are displayed both in vertical and measured depth domains along a 2D curtain section with formation tops parallel to the planned well azimuth.
In addition to the conventional LWD logs, the GWD logs generated from advanced gas analysis of the drilling mud were used for geosteering during drilling well D-08 and U-73 re-entry sidetrack wells. The LWD and GWD based geosteering were done independent of each other to test the efficacy of GWD method. Geosteering software and advanced mud gas data have been paired for high angle and horizontal well placement for the first time in Kuwait which successfully guided the well trajectory while drilling.