bluuebunny/crossref_metadata_2025_split huggingface dataset:
Performance Analysis of Recovery Processes for Extra Heavy Oil through Mechanistic Modelling and Simulation
Authors: Foo Y. Y. , Chee S. C. , Zain Z. M. , Mamora D. D. 
Published: September 2011

Abstract
The venture into various unconventional hydrocarbon resources, such as heavy oil and oil sands, has been aggressively undertaken by industrial oil players to satisfy the ever-increasing world energy demand. Heavy oil captures the global attention due to the sheer size of its oil-in-place volume. However, its high-density and high-viscosity characteristics represent a great challenge in terms of recovery optimization. Reservoir modelling and simulation has been widely recognized as an important technique to evaluate recovery efficiency as a function of the reservoir conditions and the type of recovery process.
In this paper, an extra heavy oil reservoir, the Oilfield Alpha, located in Venezuela is selected as the reservoir of interest. Conceptual models of extra heavy oil recovery, categorized into cold and thermal techniques, are addressed. Both of the thermal methods (Steam Flooding, Cyclic Steam Stimulation, Steam Assisted Gravity Drainage, etc.) and cold methods (Horizontal Well, Vapour Extraction, etc.) are studied and modelled using CMG STARS simulator. Performance indicators - typically the recovery factor, oil production rate, Steam-Oil-Ratio (SOR), etc. - for each model are evaluated and compared. The simulation results show that, after 20 years of production, the thermal methods have prevalently higher oil recovery factor, i.e. 7 - 37 % of OOIP compared to that of cold methods, i.e. 8 - 13 % of OOIP. In conclusion, the mechanistic models assist in strategic reservoir development planning at preliminary stage and, in turn, provide enhancement of oil recovery and productivity.
Dynamic Underbalance for Selective Perforation Cleaning from Hard Scale Deposits, Successful and Fully Controlled Case Histories
Authors: Vegliante Enzo , Busaidy Adil Al 
Published: September 2011

Abstract
Presence of water can often be a source of numerous problems, such as mineral scale deposition on well tubing, casing and perforation tunnels.
Abu Attifel, an onshore Libyan oilfield producing since 1972, is a multi-level sandstone reservoir where anhydrite and barite depositions have been affecting production for the past 25 years.
All the wells are cased (5" liner) hole and most of them are completed in more than one layer in commingle (in few wells all the 13 different identified layers are commingled to production).
Comparison of Porosity Estimated from Conventional Logs in Complex Lithologic Reservoirs
Authors: Xiao L. , Mao Z. Q. , Sun Z. C. , Luo X. P. 
Published: September 2011

Abstract
Six main kinds of minerals exist in the interested intervals, they compose complicated lithologies, this leads it is difficult in calculating reservoir porosity accurately by using a unified model. To remove the ambiguity of porosity calculation in complex lithologic reservoirs, two methods are attempted, they are core calibration logging method and optimization method. For the core calibration logging method, formations should be divided into two kinds of argillaceous siltstoue and dolomitic siltstone based on the difference of matrix density firstly, the formulae of these two kinds of formations are established to calculate porosity from density log. The volume physical model is also used for porosity calculation based on the optimization method. The credibility of these two models is verified by the comparison of porosity among calculated from core calibration logging method, optimization method and core analysis results. The calculated results using these two methods are all suitable for the requirement of formation evaluation and calculation of reserves, the absolute error of calculated porosity from core calibration logging method is lower than 0.4%. The optimization method is much more practicable. The principle of core calibration logging method is simply and the operational process is easy, is suggested to be used.
Improved Spacer Rheology Model for Cement Operations
Authors: Olowolagba Kolawole , Yerubandi Krishna Babu 
Published: September 2011

Abstract
In the cementing industry, it is known that zonal isolation is dependent on a successful cement job. To achieve zonal isolation, effective mud removal is recommended (Crook et al. 2001). Efficient mud displacement can be achieved with the use of spacers and flushes before cement is placed. With an increasing need to successfully complete a well on the first try, accurately modeling the spacer rheology has become key.
This paper presents results from a comparison of two rheological models. The Bingham plastic and Generalized Herschel Bulkley (GHB) models examined in this work are both used to model rheologies of spacers. For most field operations, the Bingham plastic model is used to model rheologies; however, studies have shown that using this model can lead to over-predicting yield point. The GHB model is used to model non-Newtonian fluids by incorporating the possibility that the fluid might or might not have a yield stress and that the shear stress might be a nonlinear function of shear rate.
Spacers are used to separate one fluid from another. They are designed to be compatible with the mud being used in the well. This paper compares the performance of spacer and spacer/mud rheologies at different elevated temperatures (200, 300, and 350°F) with measurements from a Model 75 HP/HT viscometer.
Results have been modeled in a computational fluid-dynamics simulator to illustrate the effects of each rheological model used to describe the well-completions fluids. The simulator modeled displacement and intermixing of wellbore fluids downhole, and these are investigated in the annulus for the simulated case.
Optimizing Paraffin and Naphthene Wax-Treatment Options Using Cross-Polarized Microscopy
Authors: Bacon Mark M. , Romero-Zerón Laura B. 
Published: September 2011

Abstract
Wax deposition is a worldwide problem for the upstream petroleum industry. Considerable resources are expended every year on trial-and-error type chemical treatment options. In a laboratory setting chemical treatments are often optimized using viscosity and pour point measurements. Viscometry and pour points can only measure bulk properties. Cross-Polarized Microscopy (CPM), however, has been shown in previous work to be a useful tool to determine individual wax crystal size and morphology. Thus, in this work CPM was used to evaluate the effectiveness of wax inhibitor treatments for paraffinic and naphthenic base oils by monitoring the morphology and size of the wax crystals before and after the application of the chemical treatments.
It has been demonstrated that there is a statistically significant reduction in wax crystal size after the wax treatment. Furthermore, the observations of the wax morphologies through CPM have demonstrated that the chemical treatment effectively inhibits wax crystal growth for both macrocrystalline (paraffin) and microcrystalline (naphthene and iso-paraffin) waxes. In addition to viscosity and pour point measurements CPM has been demonstrated to be a valuable tool to the optimization of wax-treatment options.
The Value of Experience
Authors: Alcoser L.. 
Published: September 2011

Abstract
This paper presents an improved technique for the analysis and evaluation of professional development. The oil and gas industry has braced itself for an abrupt shift in workforce expertise as the baby boomer generation reaches retirement age, commonly referred as the "Big Crew Change." The subsequent hiring frenzy observed in the past decade has led to an influx of expectant young professionals. This paper presents a personnel development philosophy for these new young professionals as well as a screening and evaluation methodology that can be utilized during the hiring and promotional process to better select talented, knowledgeable professionals with initiative. A novel metric is also presented to estimate and assign a value to the different experiences that make up a career. Three example applications are given to illustrate the utility of the proposed metric and methodology.
Water-Cut Reduction during Waterflood by Induced Fines Migration: Effects of Varying Formation Damage Coefficient
Authors: Zeinijahromi Abbas , Lemon Phillip , Bedrikovetsky Pavel 
Published: September 2011

Abstract
Decline of permeability during corefloods with low salinity and high pH water, has been widely reported in the literature. It has been explained by the lifting, migration and subsequent plugging of pores by fine particles, which has been observed in numerous core flood tests with altered water composition. This effect can be considered to provide a relatively simple method for mobility control during waterflooding. In previous research, the Dietz model for waterflooding in a layer-cake reservoir was combined with a particle detachment model to investigate the effect of fines migration and induced permeability decline on reservoir sweep efficiency and amount of injected water; the model was derived under the assumption of constant formation damage coefficient. In this work, the model was extended to the case where the formation damage, caused by captured fines, depends on absolute permeability of the rock. The modeling showed that the incremental recovery and reduced water cut, caused by induced fines migration, is lower for the case of formation damage coefficient decreasing with permeability increase, than for the case of constant formation damage coefficient.
Preparation of Novel Amphoteric Flocculant and Its Application in Oilfield Water Treatment
Authors: Song Hui 
Published: September 2011

Abstract
An amphoteric starch-graft-polyacrylamide (S-g-PAM) was prepared by inverse emulsion polymerization, subsequent hydrolysis reaction and Mannich reaction. The effects of reaction conditions on copolymerization and the use of the polymer as the water clarifier in oilfield water treatment were investigated. The application test showed that the results of oilfield waste water treatment by amphoteric S-g-PAM were better than those treated with cationic polyacrylamide (PAM), hydrolytic PAM and amphoteric PAM.
Improved Understanding of Fracturing Tight-Shale Gas Formations
Authors: Bai Mao 
Published: September 2011

Abstract
Because of the special characteristics of the tight-shale gas formations, the conventional concepts of hydraulic fracturing may become irrelevant, and the new concepts must be consequently developed to optimize the stimulation process for the tight formations. This paper focuses on improving the understanding of fracturing tight-shale gas formations through parametric sensitivity analysis of a case study. The concepts of stimulating tight formations were better understood by examining the end impacts of some critical factors, such as: a) leak-off percentage in relation to the tight-shale gas formations, b) screenout in relation to the net pressure signatures, and c) injection rate and proppant concentration in relation to the fracturing efficiency, etc. With reference to these observations, applying the proposed alternative approaches appears to be imperative to enhance the current stimulation technologies for tight-shale gas formations.
Casing Integrity Evaluation in Deep Well with Extreme Heavy Mud in Tarim Basin
Authors: Tian Jun , Wang Qinghua , Guo Qingbin , Guo Hongzhi , Liu Chuan 
Published: September 2011

Abstract
The high dip angle in formations is one of the reasons makes it difficult to drill in Tarim Basin, resulting in much longer drilling time. To counteract the high pressure from the salt layer above the targeted gas zone, 16-mm heavy casing and drilling mud as heavy as 1.9 g/cc must be used. As drill bit and pipes continue repeatedly tripping in and out the well the heavy casing may get wore thinner. Therefore it's important to know the degree of the casing wear, and to recalculate the remaining strength. Furthermore, if channel in cement behind the casing exists across the high pressure layer, it will pose another threat to corrode the casing from outside and reduce the overall strength of the casing. Hence the cement quality behind the heavy casing must be measured and assessed by reliable means. The tradition technology for well integrity evaluation has limitations in providing answers to the casing corrosion and zonal isolation in such challenge downhole condition.
A new generation of the ultrasonic imaging tool was introduced to increase the certainty of casing mechanical property measurement and cement evaluation. The technique combines the pulse-echo ultrasonic measurement with a new flexural wave measurement. The analysis from this combination allows not only a better discrimination between solid, liquid and gas for cement evaluation behind casing, but also more accurate casing information including internal diameter and casing thickness at high resolution in one trip in a well. A logging example was illustrated in this paper with high quality logging data acquired in difficult down hole conditions. As can be seen in this example, many casing grooves were found, and metal loss were up to maximum 4mm at some spots. This paper also shows a new way to look at cement quality behind the heavy casing.
Chemical Modification of Biopolymers to Design Cement Slurries with Temperature-Activated Viscosification
Authors: Reddy B. R. , Patil Rahul , Patil Sandip 
Published: September 2011

Abstract
Polymeric viscosifiers are added to cement slurries for a variety of reasons, including prevention of particle settling and control of fluid loss, gas migration, and free-water. Many of these functions are critically important after the cement slurry has been placed behind the casing but before the setting of the cement. Some functions, such as particle-settling prevention, are also important during the pumping phase. Unfortunately, most of the viscosifying polymers suffer from thermal thinning at bottomhole temperatures, especially under shear. The amount of polymer required to maintain the required level of viscosity at elevated bottomhole temperatures causes excessive surface-slurry viscosification at ambient temperature. Pumping such slurries can require higher pump pressures, or in cases where formation breakdown pressure might be exceeded. This becomes a serious challenge when the window between the fracture pressure and the pore pressure of the formation is narrow. It would be a significant improvement to oilfield cementing technology to develop polymers that do not cause excessive slurry viscosification on the surface but gradually increase the slurry viscosity as it reaches downhole temperatures, with the maximum viscosity reached at the time the slurry becomes static behind the casing.
This paper describes an economical chemical method, not based on encapsulation, for modifying biopolymers and their derivatives—for example, hydroxyethylcellulose, xanthan, and guar—that renders them insoluble in cement slurries at room temperature (RT). When the cement slurries are heated, the slurries develop viscosity, as reflected by rheological measurements. The method also provides for increased viscosification efficiency of the modified polymers because of the increased molecular weights of the modified biopolymer products. Synthesis details, slurry rheologies at different temperatures, and job-placement simulation details are presented. A possible reaction mechanism that is operative in the chemical-modification step is also discussed.
Development and Application of Foamers to Enhance Crude Oil Production
Authors: Lehrer Scott , Debord Saet Byul , Means Carlene , Crosby Simon 
Published: September 2011

Abstract
As petroleum wells age, reservoir pressure and resulting gas velocity decrease. Consequently, the hydrostatic head of fluid in the production tubing increases due to insufficient transport energy from the gas phase to lift the fluid from the well. This can decrease overall production and ultimately cause shutdowns. Initially, this problem can manifest as a production decline over time until production becomes limited; even with a fully open choke. Later, maintaining production can become even more challenging as wells begin to slug and then experience cycling production. Well production can become impossible without the assistance of artificial lift.
In gas fields foamers have successfully increased production by unloading fluid and reducing hydrostatic pressure with little capital investment. While traditional foamers effectively remove water or condensate from gas wells, they are ineffective at foaming crude oil. As there are many applications in crude oil wells where foamer could be a useful artificial lift technique, a research program was undertaken resulting in the development of a novel crude oil foamer. Laboratory testing of a wide range of crude oils and water cuts determined the types of fluid that the new foamer treats effectively. Promising lab results were obtained for fluids with an API gravity range of 25-40° and water cuts up to 60%.
A south Texas EOG Resources well was identified as a potential candidate to field trial the new foamer. Due to low reservoir pressure, this well produces intermittently, cycling on/off every seven days. Historical production rates were approximately 40 BWPD, 40 BOPD, and 250 Mcf/D. However, the well recently experienced a significant production decrease. During the two months prior to applying the crude oil foamer, production declined to only 13 BOPD and 122 Mcf/D.
A field trial at the EOG Resources well demonstrated the crude oil foamer effectiveness at increasing oil and gas production. The foamer was fed at a rate of 750 ppm through a capillary string located near the wellbore. During the trial, continuous production increased from 7 days to 12 days and the average production of oil and gas increased to 100 BOPD and 400 Mcf/D, respectively.
Carbon Dioxide, Geochemical, and Rate-of-Dissolution Simulation for Deep Storage Environments
Authors: Ceyhan Ismail , Santra Ashok , Cullick A. S. 
Published: September 2011

Abstract
Permanent underground storage of carbon dioxide (CO2) has been proposed as a potential mitigator for greenhouse gases in the atmosphere. In such underground reservoirs, CO2 is trapped through a complex combination of physical and chemical processes. Also, injected CO2 in contact with subsurface water can decrease the cement strength, deteriorating wellbore integrity. Current industry programs, such as reservoir simulators and wellbore-cementing programs, provide powerful models for the physical processes. This paper discusses a model for the remaining geochemical processes. This model is designed for implementation in existing industry programs, enabling the industry, while planning carbon capture and sequestration (CCS) projects, to take advantage of experience acquired throughout many years.
A self-contained solution procedure has been developed to solve geochemical equilibrium calculations. The equilibrium within the brine phase is computed with activity coefficients calculated by use of either the general Helgeson-Kirkham-Flowers (HKF) electrolyte model, or the more-accurate Pitzer ion model. A correlation from open literature has been selected to calculate the equilibrium between CO2 and brine phases. Once equilibrium is established, the model calculates precipitation or dissolution rates for common minerals. The solution procedure has been designed for optimum balance between robustness and calculation speed while solving the nonlinear geochemical equilibrium problem. A novel initialization scheme and a three-pass solution procedure are introduced. During Pass 1, activity coefficients are set to unity while a nonlinear minimization algorithm is used to locate the neighborhood of the equilibrium solution; in Pass 2, the first pass is repeated with the activity coefficients being calculated by use of the selected model. Finally, during the final pass, the solution is refined to the desired accuracy by the use of a nonlinear solver.
The solution model fits observed data. The CO2 solubility and brine phase pH can be computed for temperatures between 300K (80°F) and 478K (400°F), pressures up to 414 bar (6,000 psia), and brine strengths up to 6 mol NaCl/kg H2O. The more than 50 primary and secondary mineral species in the database represent common carbonate and clastic formation components. Temperature-dependent dissolution and mineralization rates can be predicted at similar conditions.
As the industry plans CCS projects, it must document projections of formation and well integrity during the project lifetime. The solution procedure is suitable for inclusion in various oil and gas industry models, including cementing simulators or reservoir simulators, to model CCS in subsurface aquifers and enhanced oil recovery (EOR). This paper provides guidance on how the algorithms should be implemented within reservoir simulators.
Gas Well De-Watering Method Field Study
Authors: Haydel Rick D. , Brink Donald J. , Acker William K. , Gassiott Gary J. 
Published: September 2011

Abstract:
A common industry problem in many flowing gas wells is the gradual build-up of well-bore fluids across the perforations over time. This phenomenon, commonly referred to as liquid loading, is typically seen in many wells that are low-producing, low in pressure, or have long perforation sets. A new gas well de-watering system has been developed to combat this problem, utilizing the reservoir’s energy to help keep it unloaded. This system utilizes a production packer, tail pipe, and carrier subs containing pressure regulating devices in order to trap and use formation gas to keep the well unloaded beneath the packer. This paper will take a closer look into the system through a study of field examples where it was implemented. In the study, one specific well from the US West Rockies Region will be chronicled from the original diagnosis of the liquid loading problem, to the design and installation of the system. Analysis plots are shown to illustrate its success. Additional field examples, within the same and different US fields, will be included to give further illustrations of this de-watering system, while also exemplifying and detailing the system’s limitations in an unsuccessful installation. A comparison analysis will be included and a discussion of lessons learned. The implementation of this system on properly selected wells can significantly impact the performance of low-producing gas wells where liquid loading destroys productivity levels over time. Although it can be run in conjunction with conventional artificial lift, this system introduces a way of utilizing the reservoir’s energy to keep it flowing naturally for a longer period, before artificial lift is necessary. This helps to reduce the overall well costs at a time when the industry is dominated by many tight, unconventional gas wells.