bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Assessment of Economical and Environmental Drivers of Sour Gas Management by Injection
Authors: Abou-Sayed A. S. , Summers C. , Zaki K. 
Published: December 2007

AbstractMany of the largest fields yet to be developed around the world contain oil, water, and high concentrations of sour gas. The fact that they are still undeveloped reflects the significant political and economic hurdles they have yet to overcome. Successful production of such fields will require careful management of surface resources (land, water, and power), subsurface resources (hydrocarbons), and associated streams (produced water, non-salable products, and E&P wastes). Several fields in the Caspian Sea are awaiting full development because they are burdened by the high expected cost and severe legal and economic risks associated with high hydrogen sulphide (H2S) content. Advantek International was contracted to undertake a comparative analysis of the engineering requirements, environmental impact risks, and economics for disposal of several associated streams in a Caspian field with 20% acid gas (CO2 and H2S).Several technologies are available to the Operator for handling the acid gas after separating from the hydrocarbons, including chemical conversion to "benign" elemental components, underground sequestration (disposal), and underground injection for enhanced oil recovery (EOR). Underground sequestration of some E&P associated streams (produced water, drill cuttings slurries, and completion fluids) have been practiced for many years, as has been injection of natural gas and CO2 for EOR. Sour gas injection, however, is a relatively new technology, with a limited experience base.This paper reviews comparative economic and risk analyses of various acid gas management options available to developing sour fields, considering the impact on recovery (including rate, ultimate total volume, engineering capacity), human health and safety risks, impacts on the environment, reputation consequences, implementation complexity, initial investment (capital and lead time), and potential regulatory restrictions (based on current North American standards, recent judicial actions, and Kyoto Protocols). The greatest opportunity for both improved value and reduced risk lies with reinjecting the acid gas for EOR. While uncertainty regarding the range of value is large, there are no risks that should be considered too severe or unmanageable to undertake this option.
Initial Results of WAG CO2 IOR Pilot Project Implementation in Croatia
Authors: Novosel D. 
Published: December 2007

Abstract
At the end of 2004, the remaining oil reserves in Croatian oil fields amounted to 8.5 million m3 and that together with high oil prices on the market represents a good base for the implementation of enhanced oil recovery methods.
After the conducted laboratory tests and simulation studies of the carbon dioxide injection process, the Ivanić oil field was chosen as the first candidate for the application of this EOR method. In order to rebuild the Gamma 2/4 reservoir pressure before the pilot project, injection of water started in 2001. The WAG CO2 process is being conducted through five cycles derived from simulation studies. After building pilot project facilities on the Iva-28 well location, the first cycle of carbon dioxide injection started in November 2003 and finished in May 2004. The next stage of the first cycle was the injection of water until November 2004. The second cycle of carbon dioxide injection started in November 2004, and finished in June this year. The main goal of this paper is to present two-year results of the CO2 WAG process, and on a broader level the knowledge accumulated in that period.
Analytical and synthetic methods of pilot project results give us information which has been tooled by inductive and deductive methods for improved knowledge and a higher level of intellectual capital. In the course of 5 WAG cycles on the production oil wells IVA-11 and 19, 76.500 m3 of oil will be produced. Oil production during the first cycle was 1900 m3, which is a good base for continuing further pilot project cycles (5 alternating CO2 and water injection cycles).
Improved Heavy Oil Recovery from Thin Reservoirs through Horizontal Well Placement and Intelligent Perforations
Authors: Tewari R. D. , Malik M. , Akbar Ali A. Husen , Naganathan S. 
Published: December 2007

Abstract
Bamboo West, a heavy oil (API Gravity 18-20) field is located in Muglad basin of south-central Sudan. Field consists of multilayered sandstone reservoirs of late cretaceous age. The reservoirs in this field are highly heterogeneous, thinly bedded, unconsolidated with high viscosity and strong aquifer support. The field is on production since July 2001 and is contributing significantly in the current 300,000 bopd production of Sudan.
Production performance of vertical wells through PCP and ESP suggests that field is facing severe problem of water coning and viscous fingering. Water cut has increased to 68 % in a span of less than 4 years causing decline in well productivity and leaving significant bypassed oil in the reservoir.
Horizontal wells were considered the best solution for improving the well productivity in this thinly bedded heavy oil field with objective for tapping the bypassed oil and delaying the water production while controlling the sand production due to low drawdown pressure and increased exposure to the reservoir.
This paper discusses about identification of bypassed oil, horizontal well placement cycle and dynamic underbalance with oriented perforation techniques that were used in Bamboo West field. A multidisciplinary approach and combination of these techniques used first time in the Middle East, Asia and Africa region resulted in the production of 1800 bopd in a horizontal well (Nearly four times of vertical well) of heavy oil from a reservoir of 0.5m thick with no water and sand production. Paper also emphasizes about different ingredients that are important for making the horizontal well successful in such fields, which can add value to the asset and results into improving the reserves and improvement in overall development strategy of the field.
Removal of Organic Nitrogen Compounds in LCO Reduce Hydrodesulfurization Severity
Authors: Yang H. , Chen J. , Ring Z. 
Published: December 2007

Abstract
The United States and Canada have set targets to reduce diesel sulphur from 500 to 15 ppm by the year 2006 and 2007, respectively. Better understanding the effects of feed matrix on sulphur removal by hydrodesulphurization (HDS) could guide refineries to select the right feed or feed pre-treatment options for their existing HDS units and achieve the required sulphur level at minimum cost. To this end, the influence of nitrogen compounds on the HDS activities of substituted dibenzothiophenes in light cycle oil has been studied over a NiMo/Al2O3 commercial catalyst using five light cycle oil feeds with different concentrations of organic nitrogen compounds. Experiments were conducted under conditions close to industrial HDS processes. Our work revealed that sulphur compounds could be removed under less severe reaction conditions if organic nitrogen compounds in LCO were reduced through adsorption by a silica column prior to HDS. The results also demonstrated that organic nitrogen compounds had more of a inhibition effect on sulphur removal by the hydrogenation pathway than by the hydrogenolysis pathway. Several approaches have been considered by refineries to meet the 15 ppm sulphur diesel specification, such as using more active catalysts, increasing catalyst volume, reducing cycle length and reducing the feedstock end point. The most refractory sulphur compounds such as 4 and 6 alkyl-substituted dibenzothiophenes become major reaction barriers when sulphur level has to be reduced. Since those sulphur compounds are removed predominately by the hydrogenation pathway, close attention should be paid to how to increase the hydrogenation activity. Commercialized Ni-Mo catalysts cannot meet the ultra-low sulphur requirement without increasing HDS severity. New active catalysts under development are mostly not entering the market before 2006. All these facts make the nitrogen removal by feed pre-treatment an attractive alternative to achieve the ultra-low sulphur goal.
The Phase Behavior of Athabasca Vacuum Bottoms + n-Alkane Mixtures
Authors: Zou X. , Zhang X. , Shaw J. M. 
Published: December 2007

Abstract
The phase behavior of Athabasca vacuum bottoms (ABVB), a 798.15+ K (525+ °C) boiling fraction comprising 32 wt. % pentane asphaltenes, + pentane mixtures is elucidated using x-ray transmission tomography. These pseudo binary mixtures are models for the development of novel heavy oil/bitumen production and refining processes. Depending on the overall composition, these mixtures are shown to exhibit three and four phase equilibria including both expected (L1L2V) and unexpected (L2L3V) phase behavior separated by a small L1L2L3V zone. These multiphase equilibria provide challenges in production environments, where miscible flooding is typically desired, but afford new opportunities for the development of separation technologies in refining. Example pressure-temperature at constant composition phase diagrams and pressure-composition at constant temperature phase diagrams, which focus on the bubble pressure region where multiphase regions arise, are presented. Limited phase equilibria data sets for ABVB + heptane, decane and dodecane are also presented so that trends for ABVB + alkane mixtures with the size of the alkane diluent can be explored. We expect these phase diagrams to provide insights to heavy oil producers and refiners in addition to providing a benchmark for testing phase behaviour models for these and related complex hydrocarbon mixtures.
New Ultra-lightweight Ultra-high Temperature Slurry Design Provided the Required Resilience for Steam Injection work in Kuwait
Authors: Kulakofsky D. , Armstrong K. , Szymanski M. , Raabe G. 
Published: December 2007

Abstract
As the global demand for energy increases, operators are being forced to drill in increasingly challenging environments. Drilling through highly depleted zones and weaker formations requires low-density cements that are pushing the limits of current technology. If the cement is made light enough to circulate, but cannot withstand downhole conditions the initial seal will only be temporary. If cement cannot be successfully circulated or fails to function shortly after placement, this can have a large impact on the drilling cost and can cause delays in production delivery due to the required remedial work. If damage is too severe, remedial work may not be enough to protect the integrity of the casing or effectively isolate the downhole formations resulting in a complete loss of the well.
Previously the industry has demonstrated the ability to both successfully circulate ultra-lightweight cement and to provide a cement that could withstand the 550°F steam environment similar to what is present in the Kuwait application, but never in the same well. This newly developed slurry design capable of circulating past these weak formations, maintaining its seal under these temperatures, and surviving chemical attack from moist CO2 (which is often present under steam injection conditions), is unique in the industry allowing the operator to proceed with plans to effectively produce their reservoir.
Slurry development including testing procedures and results will be presented. Discussion of well design, reasons for steam injection, the method for delivery of the slurry, and actual case histories will be provided.
Improving Hydrocarbon Production Rates through the Use of Formate Fluids - A Review
Authors: Downs J. D. , Howard S. K. , Carnegie A. 
Published: December 2007

Abstract
Formate fluids have unique physico-chemical properties that make them the ideal drilling and completion fluids for challenging well construction projects where extraordinary fluid performance is critical for economic success. They have been used in more than 400 wells across the world since their commercial introduction in 1993.
This paper reviews what has been published in the oilfield literature over the past 12 years about well production rates after drilling and/or completing with formate fluids. The conclusions of the review are a) the special properties of formate fluids facilitate the creation of long high-angle wells that improve reservoir access and inflow area; b) the formates tend to minimize formation damage; c) the use of formate fluids generally delivers wells with productivities that exceed expectations.
The published field case histories clearly show that formate fluids can only show their true performance potential when formulated with low levels of solids. When operators have experimented with the addition of weighting solids to formate fluids the drilling performance has been degraded and the well production rates have been unexceptional or below expectations.
Some of the information disclosed in the literature opens to question whether the use of linear core flooding is an appropriate laboratory test method for predicting the likely impact of formate fluids on well productivity.
The Stimulation Technology Research and Application in the Heavy-Oil Carbonate Reservoir of the Fracture and Cavity
Authors: Guo J. , Zhao J. , Chen L. , Li Y. , Fu Y. 
Published: December 2007

Abstract
The Ordovician carbonate reservoir in Taliram Basin is typical of fractured and caved reservoirs with thick oil layer, high temperature, deep zone and extra heterogeneity together with high density, high viscosity and high freezing point et al as common characteristics of crude oil. More than 80% wells have to be stimulated before economically producing. Based on the laboratory researches and plentiful field practices, the following stimulation modes are formed: the multiplayer acid-fracturing for long open-hole interval or layered acid-fracturing, height-control acid-fracturing against bottom water coining, a combination of hydraulic fracturing and acid fracturing. On the basis of drill so&g, logging data, well-recorded data and some geophysical data such as change rate of logging amplitude, cohere body and Jason reversion et al., model for well selecting and layer appraising is developed. We develop high-visco gelling acid, retarded acid based on surfactant, low friction resistance emulsified acid as well as insitu stiffening acid, with better retardancy, low leakage and low friction as the result, with which the damage near the wellbore is effectively solved and deeply penetrated acid-etched fracture is obtained. Furthermore, the 3D acid fracturing optimization design techniques for fractured and caved reservoir brought forward in this paper have accurately calculated the treatment data and fracture geometry, thus the effectiveness of acid fracturing is increased a lot. Up to the end of 2003, more than 220 times of application of acid-fracturing in Ordovician Carbonate Reservoir of Tahe Oilfield located in the northeast of Taliram Basin of China have indicated that 98.8% were effective, with average single-well incremental yield of 60t/d and the period of validity over 250 days, therefore, Tahe oilfield has increased the production about 311.8 × 104t altogether.
Underground Upgrading of Heavy Oil Using THAI—''Toe-to-Heel Air Injection''
Authors: Greaves M. , Xia T. X. , Ayasse C. 
Published: December 2007

Abstract
The expansion of heavy oil and bitumens production is limited by the lack of advanced upgrading facilities and technology. Surface processing, mainly by delayed coking and some hydroprocessing, is very capital intensive. This cost can be more than that for the reservoir engineering facilities. The THAI process achieves substantial upgrading of heavy crude oil directly in the reservoir, via thermal cracking and associated reaction transformations. It captures the underground upgrading because the horizontal producer well process operates via a ‘short-distance displacement mechanism’, similar to that which occurs in the SAGD process.
The results of a 3-D combustion cell test performed on Wolf Lake heavy oil are presented in the paper. Upgrading commenced as soon as the combustion front became anchored on the horizontal producer well. The produced oil viscosity was dramatically reduced, from 80,000 cSt, down to 50 cSt (average). The corresponding API gravity was increased from 10.1 to 20.4 °API (average). The quality of the produced oil was determined from a number of specific analyses, including TAN, Bromine number, SARA, and also water and gas analyses.
The first field pilot of the THAI process is to be conducted by WHITESANDS INSITU Ltd, the heavy oil division of Petrobank Energy and Resources Ltd., at Christina Lake, Alberta, Canada 1. The pilot is scheduled to start early in 2006, and if the project is successful, the new THAI technology could revolutionize heavy oil recovery and upgrading.
Hydrotreating Modeling-Helping Refiners To Face Challenges of the Future
Authors: Chen J. , Yang H. , Ring Z. 
Published: December 2007

Abstract
In order to help heavy oil upgraders and petroleum refineries optimize hydrotreater performance, a predictive hydrotreating process model is being developed to eventually predict the quality of the hydrotreated products under certain operating conditions. To establish this model, a number of important issues have been addressed and this paper summarizes the research results pertaining to these issues.
Water Injection in Viscous Oil Through Horizontal Well
Authors: Martini R. F. , Bonet E. J. , Schiozer D. J. 
Published: December 2007

Abstract
Water injection is often used as a recovery method for light oil reservoirs; however, for heavy oil reservoirs its efficiency is not so high mainly due to the unfavorable water-oil mobility ratio. For this reason, well placement is an important step of the production strategy definition because it can guarantee the economic viability of heavy-oil, deep water fields.
This work aimed to analyze the behavior of heavy oil displacement by water injection, through both experimental and numerical simulation studies. A rectangular plate filled with porous media was used; its petrophysical characteristics were determined, as well as the relative permeability and capillary pressure. Two horizontal wells were used and the laboratory test was performed in two stages: first, an oil saturation phase and then a displacement phase. Water saturation maps were generated for the two stages, in order to better analyze distortions due to friction effects in the horizontal wells.
A numerical simulation model was built to reproduce the behavior observed in the experiment and compare the friction pressure drop effects. It was further used as the basis of a hypothetical reservoir prototype, in field scale; the results from the simulations reproduced the experiment data qualitatively, however, some differences were observed. The friction pressure drop in the wellbore did not seem to affect the flow, especially according to the simulation results.
Heavy-Oil Gas Lift Using the Concentric Offset Riser (COR)
Authors: Szucs A. , Lim F. 
Published: December 2007

Abstract
The production of heavy oil presents a number of problems to deep water operators. A combination of high fluid density, hence hydrostatic head, and viscosity in the risers tied back to the floating production vessel limits the oil production rate. The Concentric Offset Riser (COR) offers a solution for convenient provision of riser base gas lift all in a single arrangement. The injection of gas at the riser base mixes with and lightens the oil, and hence enhances the production rate from heavy oil reservoirs.
The COR is a free standing and thermally efficient pipe-in-pipe riser system suitable for subsea developments tied back to a floating host vessel. The annular space has many potential uses, one of which is gas lift. The vertical riser is tensioned at the top with a buoyancy tank, and tied back to the production vessel with a flexible jumper. Such systems are being implemented in West Africa.
This paper describes the benefits of implementing the COR design for deepwater heavy oil developments.
Permeability of Breccia Facies in the Athabasca Oil Sands
Authors: Bharatha S. , Yee C. T. , Chan M. Y. , Lee D. G. 
Published: December 2007

Abstract
Breccia is a lithological facies present in the McMurray Formation of the Athabasca oil sands of northeast Alberta. It consists of mud or shale clasts embedded in clean sands. The mud content of this facies varies from 0-100% and the clasts range in size from millimetres to metres with varying degree of angularity and sorting. Breccia is common in bitumen reservoirs. From an in-situ recovery perspective, breccia can alter fluid flow and reduce the overall oil saturation due to the presence of the mud clasts. To properly characterize the reservoir flow properties, it is necessary to develop a systematic procedure to assign the vertical and horizontal permeability of breccia zones on a scale that is suitable for the numerical simulation of recovery methods such as steam-assisted gravity drainage (SAGD).
A methodology to calculate the 2-D permeability of breccia facies from core photographs and mathematical theory has been described in a previous paper. However, core photographs do not capture the three dimensional nature of the mud clasts in the breccia. In this paper, the 2-D theory is extended to 3-D by treating the mud clasts as impermeable ellipsoids. The effective permeability of breccia regions may be calculated from the permeability of the sand in which the mud clasts are embedded if the size and orientations of the clasts are known. As for the 2-D case, the results from theory are in satisfactory agreement with those from flow simulation. Using the theory specialized to the case of oblate spheroidal clasts, a procedure is developed to estimate the 3-D permeability of breccia regions, based on 2-D information from core photographs. The paper concludes with guidelines for systematic permeability assignment in the breccia zones of the oil sands as well as other similar formations.
Heavy-Oil Dilution
Authors: Argillier J. -F. , Hénaut I. , Gateau P. , Héraud J. -P. , Glénat P. 
Published: December 2007

Abstract
Heavy or extra heavy crude oils cannot be transported by pipeline without a prior reduction of their viscosity. This is commonly obtained by blending the oil with light hydrocarbons. In that case, the resulting viscosity of the mixture depends only on the dilution rate, and on the respective viscosities and densities of the oil and of the diluent. Classical diluent are light crudes, condensates, naphtha. Availability of the diluent and its possible recycling needs of course to be taken in account. In this work we have studied the influence of composition of the diluent on the viscosity reduction efficiency. In particular we show that the addition of a polar solvent to a solution of asphaltenes in toluene acts on the colloidal structure of the asphaltenes. The relative viscosity of the solution decreases, as well as the size of the aggregates of asphaltenes. In the same way, by mixing hydrocarbons and solvents owning polar functional groups in their molecule, it is shown that the efficiency of the dilution of heavy crude oils is enhanced. Hansen's theory can be used to screen the solvent efficiency. At constant dilution rate, the higher the polarity parameter or the hydrogen bonding parameter of the solvent, the greater the relative viscosity reduction of the diluted crude oil. Nevertheless, solvent owning high hydrogen bonding are generally more viscous than hydrocarbons. The influence of their interactions with the asphaltenes is hidden when the results are expressed in absolute viscosity. Polar solvents giving few hydrogen bonding give a significant reduction of the viscosity of the diluted crude oil. From an economical point of view, any improvement of the efficiency of the thinner could be a benefit for the process, by reducing the amount of solvent needed to get an acceptable viscosity, and therefore allowing a greater quantity of crude to be transported.