bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Oil Recovery by COMB-Flow: Polymer Floods Revitalized
Authors: Kotlar Hans Kristian , Selle Olav , Torsaeter Ole 
Published: December 2007

Abstract
When a typical oil reservoir reaches its economic limit after primary and secondary recovery (water flooding), the world average says that more than two thirds of the original oil is left in place1. The challenge is to develop Enhanced Oil Recovery (EOR) methods that ensure an economical tail end production from these fields.
Today’s oil price is very high resulting in better economics for EOR-concepts. There is now a trend in the business that companies again are doing research and development in this area.
Secondary water flooding leaves the residual oil capillary trapped. Surfactant injection can mobilize this residual oil by a strong reduction in the interfacial tension (IFT) between oil and water. However, a combination of polymer for mobility control, a small bi-functional molecule for enhanced solubility and reduced effect of salinity, and surfactant to lower the IFT will according to the theory have a much better effect as a tertiary oil recovery method. The concept is to search for a robust type III phase system. A polymer, a surfactant and a small bi-functional molecule in combination has been given the tentative name of "COMB-flow".
Laboratory experiments with this COMB-flow system indicate an increased recovery of OOIP by 20%.
The residual oil saturation was lowered by 12% and the residual oil recoveries ranged between 30.5% and 37.3%. Relative to the recovery obtained after traditional water flooding the recovery is enhanced almost 50%. These results were obtained on a crude oil having the in situ viscosity of 3.5 mPas at reservoir temperature. The experiments were performed at reservoir conditions.
This system will be tested further on effects on different crude oils. Furthermore, different flow regimes will be tested.
Modelling of Non-Aqueous and Aqueous Scale Inhibitor Squeeze Treatments
Authors: Vazquez O. , Mackay E. J. , Sorbie K. S. 
Published: December 2007

Abstract
The most common method for preventing downhole scale formation is by applying a scale inhibitor squeeze treatment. In this process, a scale inhibitor solution is injected down a producer well into the near wellbore formation. Commonly, these scale inhibitor treatments are injected as aqueous solutions. However, there are certain situations where an aqueous based treatment is not desirable, such as where relative permeability effects, water blocking, fluid lifting, chemical penetration or hydrate formation are of major concern.
This paper presents the results of a modelling sensitivity study comparing non-aqueous and aqueous scale inhibitor squeeze treatments. The model described can simulate the effect on the treatment life of treatment solubility in the oil and water phases, treatment strategy, adsorption properties (from the water and oleic phases), viscosity effects and wellbore friction. Of particular interest is the relationship between inhibitor solubility in the carrier and in situ phases, and the choice of phase for the overflush fluid. The relationship can have a very pronounced impact on inhibitor penetration and squeeze lifetimes.
The sensitivity study is carried out using purpose written software for scale treatments. The code is a two-phase flow, multi-component, multi-layer, radial or linear mathematical model capable of simulating both aqueous and non-aqueous squeeze treatments. The model considers the immiscible displacement of oil and water phases along with inhibitor transport in both phases and mass transfer between phases. It is capable of modelling kinetic and equilibrium adsorption and desorption from either phase. The model has been validated by comparison with analytical solutions, standard conventional single-phase squeeze calculations and multi-phase reservoir simulation calculations5. An example two-phase calculation of a specific field treatment is included, and the results are compared with the field return profiles.
Development and Field Application of a New Hydrogen Sulfide Scavenger for Acidizing Sour-Water Injectors
Authors: Nasr-El-Din H. A. , Zabihi M. , Kelkar S. K. , Samuel M. 
Published: December 2007

Abstract
In treating sour, water injectors in carbonate formations in Saudi Arabia, sulfide scavenging, prevention of sulfur and iron sulfide precipitation is a major requirement during acidizing treatments. As the acid spends on the carbonate surfaces, and in the presence of ferric iron in the injected acid, iron sulfide precipitates at pH values less than 1.9.
Iron sulfide and elemental sulfur have been implicated in injectivity decline following acid treatments on water injectors under sour conditions. Previous research work has led to the use of a new generation of hydrogen sulfide scavengers (mixture of aldehyes) for use in acidizing treatments.1 However, one of the main drawbacks of this scavenger in acidizing treatments is the formation of oily material, which can adversely affect the performance of water injectors.
This paper discusses the main reactions of hydrogen sulfide with various scavengers that can be used during well stimulation. A new scavenger that is based on hydroxyalkyl triaziane was thoroughly examined. Laboratory work included compatibility of the old and new hydrogen sulfide scavenger with live acids. The impact of the new scavenger on corrosion of low-carbon steel was also addressed.
Based on encouraging results from the laboratory, field trials were conducted on a number of wells. Post acidizing flowback samples were collected and analyzed to confirm laboratory results. Finally, injectivity results from the field trial were compared with offset well performance to validate the technical benefits of the new hydrogen sulfide scavenger.
This paper continues the discussion on the need and importance of using proper sulfide scavengers in well acidizing fluids. It will highlight the fact that there is more science than art involved in carbonate acidizing, especially for sour wells.
Efficient Permeability Parameterization With the Discrete Cosine Transform
Authors: Jafarpour B. , McLaughlin D. B. 
Published: December 2007

Abstract
The inverse estimation of permeability fields (history matching) is commonly performed by replacing the original set of unknown spatially discretized permeabilities with a smaller (lower dimensionality) group of unknowns that captures the most important features of the field. This makes the inverse problem better posed by reducing redundancy. The Karhunen-Loeve Transform (KLT) is a classical option for deriving low dimensional parameterizations for history matching applications. The KLT can provide an accurate characterization of complex permeability fields but it can be computationally demanding. In many respects this approach provides a benchmark that can be used to evaluate the performance of more computationally efficient alternatives. The KLT requires knowledge of the permeability covariance function and can give poor results whenthis matrix does not adequately describe the actual permeability field. By contrast, the Discrete Cosine Transform (DCT) provides a robust parameterization alternative that does not require specification of covariances or other statistics. It is computationally efficient and in many cases is almost as accurate as the KLT. The DCT is able to accommodate prior information, if desired. Here we describe the DCT approach and compare its performance to the KLT for a set of geologically relevant examples.
Maximising Chemical Placement in Complex Wells
Authors: Stalker Robert , Butler Kristen , Graham Gordon Michael , Wahid Fazrie 
Published: December 2007

Abstract
The effective placement of chemical squeeze treatments in heterogeneous wells and long reach horizontal wells has proved a significant challenge, with various factors including heterogeneity, crossflow and pressure gradients between otherwise non-communicating zones within the well, all contributing to an uneven placement of the scale squeeze treatment into the reservoir. Work recently presented by the authors has however illustrated the potential benefits of using modified injection fluids (in particular, lightly viscosified shear-thinning fluids) to aid uniform scale inhibitor placement in such wells to effect more even placement. This paper describes the various options available for achieving self diversion and describes the potential drawbacks associated with the viscous placement fluids commonly used for acid simulation techniques. In addition, the paper presents the results of laboratory and computer simulation investigations into the application of such fluids using novel laboratory core flood techniques, and discusses the implications of these results for field treatments. The work describes the importance of obtaining accurate in situ viscosity properties under realistic flow conditions to provide appropriate input data for computer simultaion studies and describes novel laboratory test methods for the determination of such properties. This work also illustrates the effectiveness of the use of dual core testing to provide experimental data to validate model algorithms prior to field applications.
Biodegradable Surfactants Aid the Development of Environmentally Acceptable Drilling-Fluid Additives
Authors: Miller Jeffrey 
Published: December 2007

Abstract
The additives commonly used in oil- or synthetic-based drilling fluids were designed in past years with predominant focus on providing an efficient and economical function. For nearly 50 years, the industry has relied on organically-modified clays to provide viscosity and suspension to non-aqueous fluids. However, the conventional quaternary ammonium salts used to produce these additives have shown poor biodegradability, drawing scrutiny from some regulators. Environmental restrictions governing discharges to the waters of the North Sea have now motivated fluids providers to develop cost-effective additives that deliver performance and also reduce the environmental impact.
New organic-modified clay viscosifier additives have been created using biodegradable quaternary ammonium salts. The salient features of the degradable surfactants used are similar to traditional quaternary ammonium salts, but the former include specific sites in their molecular architecture that allow them to be broken down by marine micro-organisms. When select compounds of this type are used to produce organophilic clays, the resultant materials offer functional performance comparable to traditional additives with the added benefit of providing suitable biodegradation for use in environmentally-sensitive areas.
A large number of organic-modified clays were produced in the course of a laboratory study spanning a wide range of surfactants. Many of the compounds examined could be used to make viable viscosifier additives, but only a select few that were biodegradable could sufficiently modify the clay surfaces. Performance testing showed that the new clay-surfactant complexes can provide results comparable to a conventional organophilic clay in a paraffin-based invert emulsion system. While a slightly higher concentration of biodegradable clay was needed to obtain comparable yield point values, in one case the increase was less than three pounds per barrel.
Aligning E&P Organizations to Manage Large Capital Projects
Authors: Luan Pete , Wray John 
Published: December 2007

Abstract
Planning and executing large, high risk, capital projects in frontier areas means that E&P organizations have had to retool their project delivery systems. While many energy firms have started the development of more robust project management processes to support these high capital expenditure (CAPEX) projects, implementation of this new way of doing business is meeting limited success.
Business leaders feel that they must effect change because of lack of predictability in delivering major E&P projects as evidenced by the above headline. This lack of predictability includes CAPEX overruns, late project completions, overly optimistic recoverable reserve estimates, etc.
By some estimates, 50% - 80% of enterprise level initiatives are deemed failures by organizations. How much stockholder’s equity has been liquidated attempting to implement a new way of doing business yet meeting only limited success, if any at all?
Robust Well-Cost Estimation Using a Support Vector Machine Model
Authors: Bhuddharaju Pradeep , Laskar Sandipan , Samuel G. Robello 
Published: December 2007

Abstract
The preparation of cost estimates for a well is the final and most critical step in well planning. Traditionally, well costs are estimated by using a deterministic calculation procedure with time and cost inputs, or by using probabilistic methods. Because in many cases the estimate determines whether or not the well will be drilled, the credibility of the estimated cost is crucial.
This paper describes the development of a support vector machine (SVM) -based application. In addition to estimating the cost, this application also indicates the percentage of accuracy in the prediction, thereby proving the credibility of the predicted cost estimate. The proposed methodology enables drilling industry personnel to estimate the risk of the project during well planning and during drilling. The analysis from such a model is based on the constraints of different drilling variables. Extensive simulations have been carried out and are reviewed in this paper. The paper also includes two case studies of well cost estimation where the SVM methodology successfully the predicted risk involved in the completion of the wells.
The Application of Expandable Tubulars in Casing while Drilling
Authors: Gupta Yash , Banerjee Sudeepto N. 
Published: December 2007

Abstract
The basic idea of a mono-bore well has been a dream in the oil and gas industry since its very origin. With the development of new technologies, this dream is becoming a reality. The two most preferred methods for drilling a single diameter well are the casing while drilling system and the expandable tubulars. Both these methods are useful in their respective fields of applications. But both these technologies have not been used simultaneously, not even in a single well as separate methods for drilling.
This paper discusses the possibility of combining these two technologies, namely the casing while drilling method and expandable tubulars, for tapping the advantages of both these technologies. The main advantages that are evident by this combination is the savings that are achieved, both in terms of monetary and time. Also further reduction of tools involved leads to less chances of failure, again leading to savings in terms of manufacturing and logistics. This paper also focuses on the different mechanical properties of the casing type to be used for this specific purpose and discusses general complications that might arise in practical field applications of the same.
Maximizing Well Productivity through Water and Sand Management—A Combined Treatment
Authors: Nguyen Philip D. , Ingram Stephen R. , Gutierrez Mauricio 
Published: December 2007

Abstract
Production of large volumes of water, coupled with production of formation sand and fines from oil and gas wells, often curtails the potential production of hydrocarbon. It is therefore highly desirable to decrease the volume of water and mitigate the solids produced from producing wells. Water and sand control generally have been addressed as separate problems with different treatment solutions. This paper discusses the development, and presents the field testing results, of a 2-step process that combines both water- and sand-control treatments into a single treatment.
Laboratory experiments were performed to examine the impact of these combined treatments. The relative permeability modifier (RPM) treatment results in water permeability reduction with little or no reduction in permeability to oil. Treatment with a consolidating agent transforms the unconsolidated formation sand and/or loosely packed proppant into a cohesive, consolidated, yet highly permeable, pack. The combined process has been field tested successfully. Results from field tests have shown that this process helped reduce on average 50% of water production, effectively eliminated the production of formation sand, and allowed the wells to withstand high production flow rates.
Mercury Removal System for Upstream Application: Experience in Treating Mercury From Raw Condensate
Authors: Sainal Muhamad Rashid , Shafawi Azman , Mohamed Ir. Abdul Jabar 
Published: December 2007

Abstract
This paper presents an approach undertaken by PETRONAS Carigali Sdn Bhd, an E&P subsidiary of PETRONAS in selecting, optimizing and installing a mercury removal system in one of its operations in Malaysia. It focuses on the treatment of the raw condensate stream that was noted as having much higher mercury content as compared to the gas stream. Since the experience in mercury removal in raw condensate is limited, this paper also presents the work done to mitigate the risks and improve the removal performance. The paper shares the initial performance of such system and the issues faced to sustain its long term effectiveness.
Through operation surveillance, mercury was observed to be present in the hydrocarbon delivered by PETRONAS Carigali to its downstream customers. A Mercury Removal Project was initiated in March 2005 to treat and remove the mercury from the hydrocarbon. The Project was conducted on a fast track basis. Adsorbent technology was selected following a thorough evaluation that includes carrying out performance tests in the laboratory. The project is among the first in the world to remove mercury from raw condensates. (The gas was not treated after the data established that the mercury content in the gas meets specifications).
The project was completed in stages with the first system installed in March 2006, and the second in July 2006. The results show that the units managed to remove mercury from the condensate with more than 95% efficiency. The project demonstrated that the treatment of mercury could be done upstream prior to exporting the hydrocarbon liquids. It is an approach that should not be ruled out in the gas processing value chain whether for reasons of risks mitigation or value improvement or both.
Mercury is a natural occurring element and could be present in varying concentrations and of various species in oil and gas fields. Mercury is not only hazardous to human health and the environment but could also attack equipment components that have mercury reactive materials, leading to a potential catastrophic failure to the plant.
Neural Networks Can Enhance Fuzzy Corrosion Modeling
Authors: Hajizadeh Yasin 
Published: December 2007

Abstract
Corrosion in the petroleum industry is one the major concerns of the managers and engineers. Both upstream and downstream parts face this problem and the companies spend billions of dollars in this case. To remain competitive with the world market and win the game, this cost must be kept to a minimum and here the large demands for a reliable corrosion prediction model do exist which we can use in our decision making. On the other hand in many engineering problems the available information is vague and sometimes measured data or export knowledge is too imprecise to justify the use numbers. Fuzzy logic is a good solution here and helps us to compute with words. But the problem is that you can not train the fuzzy systems so neural networks may be useful here to add learning capability to fuzzy systems.
Using fuzzy logic as a powerful tool, 3-D corrosion models have been generated in the previous work. In this paper the problem of corrosion modeling will be discussed form the hybrid neurofuzzy approach. Teaching the fuzzy system with neural networks, and using pressure, temperature, oil and gas production rate, CO2 and H2S mole percent of the flow as the model inputs and the corrosion rate as the output, 3-D surfaces for the corrosion have been obtained and the prediction results of the model which is based on the pattern recognition between input and output parameters is tested. These graphs can be used as a reliable tool in corrosion prediction by managers and engineers.
Relative Permeability and Wettability of Rocks Obtained From Their Capillary Pressure and Electrical Resistivity Measurements
Authors: Attia A. M. 
Published: December 2007

Abstract
Relative permeability and Capillary pressure characteristics of reservoir rocks are usually determined using core analysis. In the absence of representative core sample, resistivity log-derived water saturation in the transition zone may be used to depict capillary pressure curve and, in turn to determine relative permeability characteristics from petrophysical correlations. Most of reported research works have investigated the relative permeability from a steady state and unsteady-state techniques. The technique of measuring relative permeability using resistivity measurements almost absent from the reported works. Hence, the main objective of this work is to determine the relative permeability from the resistivity measurements and compare it with those obtained from capillary pressure data using the same cores. Also, it is intended to find out which models could be used for calculating the relative permeability from capillary pressure realizing a best fit matches with the relative permeability obtained from resistivity measurements. In addition, to determine the types of wettability from resistivity measurements. Results and analysis indicate that the capillary pressure and resistivity measurements result in significant different irreducible water saturation values. This, in turn, results in substantially different relative permeability characteristic curve. Also by analogy, a semi analytical method was to be developed to infer relative permeability from resistivity index and free water saturation. In most cases, the Brook-Corey and Corey models, may be the best fit match to the relative permeabilities of wetting and nonwetting phases respectively obtained from resistivity measurements. Therefore, wettability was determined using the values of water saturation exponents, water saturation at crossover point. The results indicate that, the wettability of Berea cores was neutral-mixed wet. However the wettability of the synthetic cores compacted at 3000 psi, was strongly water wet.
The Effect of Tool Joints on ECD While Drilling
Authors: Simoes Sarita , Yu Mengjiao , Miska Stefan , Takach Nicholas E. 
Published: December 2007

Abstract
As the oil and gas industry moves toward drilling ultra-deep and deepwater wells with small margins between pore pressure and fracture gradient, management of ECD becomes a key factor in the successful drilling of these wells. ECD is governed by the hydrostatic head of the mud column and frictional pressure loss in the annulus, and therefore is influenced by many factors such as well and drillstring geometry, drilling fluid rheology and flow rates. Many theoretical and experimental studies have dealt with the flow of fluids through pipes and annuli for friction pressure loss calculations. However, the effect of tool joints in estimating pressure losses in annuli in many cases is underestimated or ignored. Although a single tool joint is short and does not increase the frictional loss drastically, the overall contribution to the increase in ECD by all the tool joints in the wellbore can be significant. Therefore, there is a strong need to investigate the effects of tool joints on ECD control.
This paper presents results for a theoretical study conducted through Computational Fluid Dynamics techniques to evaluate the influence of the tool joints on ECD for different wellbore geometries, drilling fluids and flow rates. It is found that the effect of the tool joint on the annular friction pressure loss is significant and should be taken into account in the optimal hydraulic program considerations.