bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unique Cement Design to Mitigate Trapped Annular Pressure TAP Between Two Casing Strings in Steam Injection Wells
Authors: Brown Jeanna , Kenny Neil , Slagmulder Yves 
Published: December 2016

Abstract
Shell has experienced production casing deformation on several infill wells in an existing thermal development project in Canada. A full investigation identified trapped annular pressure (TAP) caused by unreacted water fraction in set cement between casing strings as a potential casing failure mode. A novel and innovative application of an existing technology (a cement blend incorporating hollow-glass microspheres) was developed, tested and implemented as an effective means to provide pressure relief in the cemented casing-casing annulus on steam injection wells.
Thermal cement blends from two suppliers were used in the testing program. The test slurries were cured in a test cylinder until compressive strength development tapered off, and then heated in increments to 320°C while pressure was recorded. Typical thermal blends containing a range of concentrations of hollow-glass microspheres were tested in this manner to establish a slurry design that would prevent the pressure build up from surpassing the temperature de-rated collapse resistance of the casing.
The tests using typical thermal cement blends with no glass bead additive resulted in rapid increase in pressure as the test cell was heated, and exceeded the temperature de-rated collapse value of the production casing string at temperatures much lower than typical steam injection temperatures. Tests performed on blends containing the glass spheres showed consistency and repeatability in results, and pressures were well below the de-rated collapse pressure of the production casing string at the maximum steam injection temperature.
Based on preliminary results, this investigation has concluded that the cement blend containing 10% BWOC hollow-glass microspheres is a viable alternative to conventional thermal blends, capable of providing hydraulic isolation to meet regulatory requirements and industry best practices, with the added benefit of providing a mechanism to mitigate TAP on steam injection wells.
Cost Optimization of a Thermal Recovery Project in Heavy Oil Green Field - Kuwait
Authors: Ortiz-Volcan J. L. , Behbahani F. M. , Akbar M. G. 
Published: December 2016

Abstract
This paper presents a practical approach toward cost optimization of a thermal recovery project in a heavy oil green field in Kuwait. This objective is achieved by understanding total cost breakdown for Capital Expenditure (CAPEX) and Operating Expenditure (OPEX) for all assets (natural and physical) during the economic horizon of the project and the identification of root causes of cost drivers that cause the total cost to increase, potential project delay and poor performance.
Complex cause and cost effect relationships are visualized using causal maps and loss causation models for seven most important group of risks during field life cycle. Uncertainties are addressed by comparison with analog fields undergoing Cyclic Steam Stimulation and Steamflood. One-way sensitivity analyses and stochastic modeling of key cost drivers solve a critical uncertainty, lack of OPEX data during commercial operations. Other application includes assessment of risks affecting total cost per barrel and selection of best strategy for risk mitigation with their costs and benefits.
A work vs. total undiscounted cost breakdown structure showed the 12 most critical cost drivers, where 70% corresponds to OPEX and 30% to CAPEX, fuel for steam flooding being the highest with 55%. A map with 17 elements was analyzed for associated physical assets, 2 causation maps describes 14 causes of total costs for surface and subsurface, including identification of key uncertainties and risks. Seven most significant groups of risks (total 66 risks) were modeled to visualize the impact on cost, people (health & safety) and environment with all mitigation actions ranked by cost benefit.
Understanding causes of high cost per barrel and their relationship with uncertainties and risks for a green heavy oil field, is a formidable tool for multidisciplinary cost optimization as it provides a common language that is understood by all disciplines involved.
An Approach to Mitigate Subsidence in Soft Rocks through Coupling Surface Tiltmeter and Injection/Production Data
Authors: Temizel Cenk , Kirmaci Harun , Inceisci Turgay , Wijaya Zein , Balaji Karthik , Suhag Anuj , Ranjith Rahul , Tran Minh , Al-Otaibi Basel , AlKouh Ahmad , Zhu Ying , Yegin Cengiz 
Published: December 2016

Abstract
Diatomites are high-porosity, low-permeability reservoirs with elastoplastic properties and high geo-mechanical responsiveness. They have a great potential for oil recovery despite these drawbacks. Withdrawal of fluids from the reservoir rock leads to subsidence causing compaction and shear stresses. This disturbed stress distribution results in well failures that causes loss of millions of dollars. Successful maintenance of pressure support through optimum injection/production is key to preventing subsidence to mitigate the risk of well failure and achieve better sweep efficiency for recovery.
There have been different approaches to tackle subsidence and well failures in diatomites, including the use of ‘backpressure method’, coupled with a neural network to optimize injection-production to ‘balance’ the rock in terms of stress-distribution and thus decrease well failure due to shearing. However, using such methods may mask other problems the well is experiencing including several mechanical issues that influence production. Another existing approach, satellite-imaging (InSAR) cannot be used to take real-time actions that is crucial in diatomites.
Surface tiltmeter data is collected to undertsand the relationship between injection/production and resulting surface deformation, which also provides information about well-to-well connectivity. A neural network-based approach is followed to determine the nonlinear relationship between surface subsidence/dilation and injection-production. This is then used to build an objective function that works to minimize the differences between well-to-well subsidence/dilation measured by the tiltmeters, by adjusting injection-production for the wells.
In this paper, a method that harnesses real-time surface tiltmeter data to adjust injection-production distribution in diatomites to decrease well failures is used beyond the existing applications of surface tiltmeter, for instance, in the areas of detection of early steam breach to surface in steam operations and fracture orientation. This method also provides real-time data for robust reservoir management of such reservoirs where satellite imaging is not effective.
Molecular Weight Correlation for Crude Oil in the Fields of Saudi Arabia
Authors: AlMatouq Hana 
Published: December 2016

Abstract
Molecular weight determination of crude oil samples is an important factor in the process of oil production in any oil field. This paper shows an experimental study to develop a correlation that numerically predicts the molecular weight of any crude oil sample with a known density.
The current method used in the laboratory to test the crude oil samples for average molecular weight value is the freezing point depression method, which is implemented in an automated cryometer 1. This method takes a relatively long time to perform. The use of the developed correlation will help in predicting a numerical estimation of the expected average molecular weight value for each tested sample. It will also help as a quality check step on the values we get from the performed experiment. Moreover, if this correlation continues to give accurate results, it can be used as an alternative method to the laboratory test.
The author carefully analyzed experimental data of average molecular weight as well as density to look for a correlation that relates both quantities. The analyzed data was of crude oil samples from thirty different fields in the Saudi Arabian region. This analysis required assuming that density is the only factor affecting the molecular weight value at constant temperature and pressure.
After analyzing all the experimental data generated in the laboratory, we successfully developed a correlation that gives accurate and comparable results within 2% average error to the obtained experimental values. These results were found for samples from several but not all of the Saudi Arabian fields. The study did not include new exploration fields or fields with insufficient data. Furthermore, this study concentrates solely on black oil samples and excludes gas condensate samples.
Wellbore Organic Deposits Dissolution Using An Emulsified Solvent System - Field Treatment
Authors: Al-Hajri Nasser M. , Al-Ajmi Mohammed D. , Al-Ghamdi Abdullah A. , Green Todd A. , Taq Ali A. , Al-Subaie Fehead M. 
Published: December 2016

Abstract
This paper will present a field case study to clean out wellbore organic deposits using a high flash point emulsified solvent system. Wellbore organic deposition was present in a horizontal water injector, Well-X, at 140 feet (ft.). The water injector is a pilot well completed above a tar mat formation to provide reservoir pressure maintenance. The wellbore deposits have restricted wellbore accessibility and caused loss of injection potential. Downhole samples from the obstructing material were collected from the wellbore using a wireline bailer. The samples were analyzed in the laboratory using solvent extraction and infared spectroscopy. The downhole samples were found to be comprised mostly of maltene which was present in the form of saturates, aromatics and resins at varying weight percentages. The organic deposits also contained asphaltene.
The wellbore organic materials underwent extensive solubility testing at a simulated downhole temperature. Several solvent systems were evaluated such as xylene in diesel and aromatic solvent systems. Based on the performance of the dissolution systems in terms of solubility and soaking time an emulsified solvent system comprising n-methylpyrrolidone, fresh water, emulsifier, and an aromatic solvent was chosen for field deployment. Other factors such as chemicals hazards and cost were also considered as part of the treatment fluid selection process.
The treatment fluid deployment was carried out using both the bull heading and coiled tubing (CT) techniques to ensure full exposure of wellbore organic deposits to the emulsified solvent system. The treated deposit solutions were flowed back using zero discharge system and their organic contents were inspected periodically. The field treatment design, job execution, contingencies, and what-if scenarios will all be discussed in this paper.
3D VSP Surveillance of Thermal Heavy Oil Recovery in Kuwait
Authors: Ren Zu Biao , Al-Haqqan Hamad , Ahmad Fatma , Tinnin John , Hamilton Angus 
Published: December 2016

Abstract
Some key challenges in thermal heavy oil recovery include how to monitor steam flood effectiveness and cap-rock integrity. Kuwait Oil Company acquired baseline 3D VSP surveys in January 2016 as geophysical surveillance projects for a steam flood pilot. This paper presents a technical approach of 3D VSP acquisition design, data processing, seismic inversion, quantitative interpretation and its application for the monitoring of steam movement.
Applying pressured steam to a reservoir can lead to damage of overlying cap-rock and could cause energy leakage through fractures. The technique of baseline 3D VSP and future time-lapsed 4D VSP are designed to image steam flood movement within the reservoirs. The possible applications of 3D/4D VSP technology include imaging the steam chamber size of a 30-day steam cycle, reservoir characterization and investigating integrity of the sealing cap shale.
Extensive planning and immaculate execution of the 3D VSP operations resulted in timely completion of survey acquisitions with high quality data. Because of the optimized acquisition parameters, the frequencies attained in these surveys were more than 30% higher than previously achieved in this same area. Extensive modeling enabled innovative customization of the acquisition design, optimized parallel processing, and interpretation techniques have allowed for a time effective acquisition-to-results turnaround that may affect the second cycle of the steam injection program. Resulting analysis on processed data clearly indicate the steam flow shape and direction. These significant results are providing important input for development decisions.
The reduction of the bin size from high fold and tight source / receiver distribution proven to be an effective and high quality method for imaging shallow geological target reservoirs. The resulting high frequencies obtained allowed for better vertical and spatial resolution, which enabled steam chamber size estimation and study of cap-rock integrity.
Estimating and Modeling Fluid Saturations in Viscous-Oil bearing Clastic Reservoirs Lithological Controls on Reservoir Properties and Fluid Contacts
Authors: Jha M. K. , Al-Dohaiem K. , Saikia P. , Al-Ali Y. , Al-Rashdan S. , Shanat F. H. , Ahmed K. , Ahmad F. , Tye R. , Dharanidharan B. , Prasse E. M. , Veedu F. Koyassan 
Published: December 2016

Abstract
Identifying oil-saturated versus water-saturated sands in shallow, unconsolidated, viscous-oil-bearing terrigenous-clastic reservoirs of Kuwait field is challenging. Field appraisal was based upon seismic, core and wireline-log data from 19 wells. Static and dynamic models incorporating all subsurface data were built to estimate oil-in-place and forecast production. Estimating and modeling fluid saturations in reservoir zones was accomplished by integrating core, dielectric-resistivity, Nuclear Magnetic Resonance (NMR) and Wireline Formation Tester (WFT) data. Wells were drilled along a northwest/southeast-trend, thus geologic and reservoir-property variability in east and west parts of the field are uncertain.
Stratigraphy and lithologic properties in these Miocene-age fluvial to shallow-marine strata impart a complex 3–D fluid distribution in the field. Repeated shoreline progradations and retrogradations deposited a stratigraphic succession defined by five facies-associations (i.e., shoal, tidal flat, tidal channel, lagoon, sabkha). Five lithofacies (i.e., shale, shaly sandstone, sandstone, carbonate-cemented sandstone, evaporite) were identified from core, elemental spectroscopy logs, and X-ray diffraction (XRD) data. Facies associations and lithofacies models were built using a combination of multiple-point statistics and sequential-indicator simulation. Lithofacies distribution in the static model was constrained by the facies-association distribution; reservoir-property distribution (e.g., porosity, permeability) was conditioned by lithofacies.
Discrete reservoir zones were defined to separate oil-saturated versus water-saturated sands. The volume and position of oil-bearing sands are controlled by the defined zones and permeability distribution. The oil-filling process in these viscous oil-bearing reservoirs is typically controlled by the pore throat distribution with the migrating oil taking the path of least resistance. Due to the presence of stratigraphic-flow baffles, fluid contacts vary from sand-to-sand vertically and laterally. Log data, core descriptions, ultraviolet photographs, WFT and pressure volume temperature (PVT) data guided the interpretation of lowest known oil and highest known water levels, thus reducing fluid saturation uncertainty in the field.
Geosteering Application in Heavy Oil Environment, Study Case in North Kuwait
Authors: Sitinjak Eri Sarmantua , Hasan Fawwaz , Abbas Faisal Fadel , Choudhary Predeep Kumar 
Published: December 2016

Abstract
The field study is in northern part of Kuwait targeting heavy oil formation, known to be shallow unconventional oil reservoir. It is heterogeneous shallow sandstone reservoir (500ft TVD) with low maturity oil, has low natural pressure, and poorly consolidated. Mud losses known to be the main risk of horizontal drilling in shallow heavy oil environment and the heterogeneous including continuity of the sand are also challenging for geo-steering team in order to place the well in the optimum position. Seismic is not available, however due to high offset well density a good correlation map has been produced. We are using formation tops from offset wells to delineate the continuity of the sand and trend of the structure dipping, we called it as shooting point method, which is assuming the trend of the structure from one offset well to another nearby offset well. The resistivity contrast will be expected to give us around 9 ft depth of detection (DOD) for our Azitrak resistivity tool based on Picasso plot. We made some scenarios for exiting the reservoir and it showed us some early warning 80ft to 180 ft prior to exit the reservoir. We use Autotrak, Azitrak dan Litotrak formation evaluation and density imaging tool to geo-steer and optimally place the wellbore inside 1B sandstone. The expectation of drilling the lateral was below 1000ft MD due to wellbore stability issue. From the correlation of available offset well it is clearly seen, there are two sand bodies in heavy oil target sand. The thickness is around 30-40 ft TVD and the structure was expected to be flat or a little bit dipping down. The well was landed in the middle of 1B, based on correlation of actual landing point log data to the nearest offset wells. Distance to bed boundary (D2B) showed local conductive layer from bottom since drilling the lateral section, which was not the response of base of 1B sand. So it was recommended to go down in stratigraphy in order to place the trajectory at the bottom part of 1B sand. In order to minimize wellbore stability issue along the lateral section, Bakerhughes recommended to maintain consistent faster ROP (80-100ft/hr) and effective hole cleaning. In the middle of lateral section of well B (1750ft MD) the well trajectory was inverted for the optimum production purposes to total depth (2250ft MD). Total lateral length achieved is 1116ft MD which covers 100% of the lateral length. Shooting point method in defining the rough structure trend from one well to another well was effectively applicative in the field, where current structure after drilling the lateral section is almost flat or slightly dipping down same as predicted before.
Well Design, Construction and Completion Considerations in a Thermal Oil Sand Development Project
Authors: Zatka Mirko 
Published: December 2016

Abstract
The sub-surface design of wellbores and associated well completions to be used in thermal oil sand operations must take into account a significant number of criteria and factors to ensure the delivered wells can provide the required long-term operating life and reliability required of them, especially when it comes to operating safety.
These considerations cover a wide range of primarily technical aspects, including the location and layout of the wells at surface and sub-surface; type of service the wellbore will be used for, therefore, the construction materials to be used and their properties; recovery process impact on the wellbore design including the geology and reservoir behaviour; tubing size, perforation and sand control considerations; artificial lift requirements; downhole operation selectivity; produced fluid compositions and conditions, and well operability requirements.
The level of detail that needs to be considered for each of these depends on the stage of project development. As work progresses, the level of detail increases in order to be able to arrive at an appropriate and balanced technical and safety design, as well as associated cost, once the final concept selection is made. The subsequent "Detailed Engineering" phase should be used only to fine-tune any remaining questions or issues that may arise in preparation for final project approval, and to provide the required definition of each element in order to be able to build / purchase / install / operate it. It is not discussed in this paper.
Produced Water Treatment Using Membrane System for Heavy Oil Operations
Authors: Chen Cheng , Widiyanto Adi , Hobbs Ron 
Published: December 2016

Abstract
Excess produced water is always a challenge for heavy oil operations with steam flood. The management of produced water is critical to oil recovery in steam flood. There are several options for produced water disposal including downhole injection and benfitial reuse after proper treatment. Downhole disposal is not always available and the capacity may not be sufficient. For benefitial reuse, we always need to meet stringent environmental regulations for local government. Some common regulated components in produced water are pH, COD, OIW, ammonia, phenol and TDS etc. Membrane technology is one of the most promising and cost-effective ways for the treatment needs. Here we propose a membrane process design to remove COD, OIW, ammonia, phenol and TDS to meet environmental regulations with significant less CAPEX and OPEX. We have conducted laboratory membrane pilot test using different membranes to optimize membrane process design. The results indicated that both ammonia and phenol can be removed using one pass or two pass RO system if proper pretreatment is conducted. We were able to meet the treatment targets for final permeate from membrane testing. Scale formation in RO membranes can be managed by application of proper antiscalants. Cost evaluation of proposed membrane process was also conducted. Both CAPEX and OPEX are much lower than commercial produced water treatment packages. In summary, this proposed membrane process shows great economical potential for produced water treatment for beneficial reuse in heavy oil operations.
Integrated Management of Waste Heat in SAGD Operation in Liaohe Oilfield
Authors: Jin Fu , Shunyuan Zhang , Bingshan Liu , Chen Chen , Shifei Dong , Weiwei Yin 
Published: December 2016

Abstract
SAGD technology has been applied by scale in Liaohe Oilfield China, where high pressure steam is injected in a horizontal well to drain tight oil into the lower production well. However, much waste heat has not been exploited, including heat of the hot production fluid, flue gas and HPHT brine separated by the steam-water separator in the boiler.
On-field researches were carried out on many dual-horizontal wells in Liaohe Oilfield to learn the present operation situation and technical capabilities, while thermodynamic models of various types were established and experimental apparatuses were utilized to analyze the present thermal distribution and each of the above waste heat sources. Effects of various media, flow rates and temperatures on heat utilization and the heat deficit rate were studied on the assumption that 1t crude oil was produced each hour.
The high temperature production fluid may be used to heat water in the boiler first and then used as the heat source of the absorption heat pump, so that heat is transferred from the low temperature heat source to the high temperature heat source and the low grade heat energy is recycled. Waste heat of flue gas may be utilized to help combust air and the thermo-coil may be used as the air preheater, which improves boiler's heat efficiency. As a high grade waste heat, the HPHT brine separated from moist steam in the boiler takes up 20% of the total water and shall not be only used to heat injected water. Instead, it may be used to achieve flash evaporation. Thus, waste water is heated and distilled water is recycled.
The optimized waste heat recyling proposal applies the thermo-coil air preheater to recycle flue gas, flash evaporated hot brine to evaporate waste water and high temperature production fluid to heat boiler water. On a basis of the same fuel consumption volume the recovery rate of crude oil is enhanced by 31% and marketability of it is improved by 8.6%. More energy is saved and recycled, which contributes to the green oilfield construction.