bluuebunny/crossref_metadata_2025_split huggingface dataset:
Novel CO2 Capture Process Suitable for Near-Term CO2 EOR
Authors: Jain R.. 
Published: February 2011

AbstractRecent studies have indicted that more than 40 billion barrels of additional oil can be produced economically with CO2-EOR for a low CO2 capture cost and an oil price above $70/bbl. More than 10 billion tons of CO2, the equivalent of CO2 emissions from 50 1 GW power plants over a period of 30 years, can also be stored using CO2-EOR. Unfortunately, the cost of CO2 capture using current state-of-the-art absorption based post-combustion CO2 capture technologies is very high because of 25-30% reduction in the power plant output, and an 80-100% increase in the capital cost. These technologies are not viable in the near-term for CO2-EOR without a high market price for CO2. For this reason, most of the currently proposed CO2-EOR projects are based on IGCC plants that are yet to be built. This paper discusses a novel capture process based on physical sorption. Unlike the absorption based processes this process has a much lower CO2 capture cost, does not require the additional removal of NOX and SOX, and can be easily retrofitted to an existing power plant or refinery.Based on extensive pilot testing over a period of over three years, detailed engineering designs, and detailed costing, the process can provide more than 99% CO2 purity and more than 90% CO2 recovery, and can produce pipeline quality CO2 with 60% lower capital cost and at least 40% lower energy penalty compared to the best current technology. The process will be tested with flue gas from a combustion source early next year and can become commercially available in 3-4 years. Lower capital requirements and &lt;16% parasitic power can allow compressed CO2 production for less than $30/ton from existing power plants, refineries and chemical plants. This can allow many power plants and refineries near existing CO2 pipelines to become potential CO2 sources for near-term CO2-EOR in many locations in the United States.
Tengiz Sour Gas Injection Project
Authors: Darmentaev Sabyrzhan , Yessaliyeva Arailym , Azhigaliyeva Aizada , Belanger Dave , Sullivan Mike , King Greg , Feyijimi Tayo , Bateman Phil 
Published: February 2011

Abstract
Gas Injection into the Tengiz oilfield began in January 2007 with sweet gas injection as Phase 1 of the SGI pilot project. Phase 2 of the project, sour gas injection, began in October 2007, but was interrupted due to initial injection start up problems. Continuous sour gas injection began in January 2008. As part of the SGI Surveillance Plan, a variety of reservoir measurements are routinely acquired to monitor the progress of the flood.
The SGI project has four signposts for success: Compressor reliability, Injectivity, wellbore durability, and reservoir performance. The sour gas compressor at Tengiz was the first of its kind and has had greater than 90% availability when SGP has been operational. Injectivity has exceeded expectations and wellbore durability has also been excellent. The fourth area is reservoir performance and all indications are that the reservoir is performing as expected.
The SGI project consists of seven inverted five-spot patterns. To expedite data acquisition, the SGI well patterns were designed to include one "super-spot" pattern (twin injectors 100 m apart providing dedicated injection support to different geologic layers) and three short-spaced producers (producer-injector spacing approximately 1/3 of the standard spacing). Tracers, pulse tests, multiphase meters, gas saturation logging, and production and injection are used to monitor and understand reservoir performance. A specialized simulation model (Monitoring Model) was constructed which uses local grid refinement in the SGI pattern area.
On August 22, 2008, gas breakthrough occurred in Well T-318, the first of the short-spaced producers. This breakthrough was predicted with the Monitoring Model. Predictions from Monitoring Model suggest most likely breakthrough is near top of reservoir, and this was substantiated by logs. The gas injection project will continue to be closely monitored to improve our understanding and reservoir forecasts.
Using Electrical Borehole Image Log to Optimize Formation Pressure Sampling and Its Integration to Determine Structural/Stratigraphic Break in a Tight Carbonate Reservoir at Karachaganak Field
Authors: Juandi D.. , El-Battawy A.. , Russo J.. , Chittick S.. 
Published: February 2011

Abstract
Karachaganak field hosts world-class gas and liquid reserves in an Upper Devonian to Lower Permian isolated carbonate platform. A complex diagenesis over carbonate rocks extends from syndepositional to deep burial settings. Effective porosity in most parts of the reservoir is secondary in nature, such as vugs and fractures, with average porosity considered as low. The complexity of carbonate reservoirs is well known owing to the nature of their heterogeneity and cannot be resolved by conventional openhole logs because of limited vertical resolution and large azimuthal dependency.
Electrical borehole image logs provide both the small-scale resolution and azimuthal coverage to quantitatively resolve the heterogeneous nature and are used routinely to determine subseismic structural or stratigraphic events, as well as to optimize the selection of formation pressure and sampling points. The use of a high-resolution electrical borehole image log helps place the tool probes at optimum formation and depth locations, thereby reducing risk and operating time. Analysis of pressure gradients can confirm subseismic reservoir barriers that had been earlier interpreted as structural or stratigraphic breaks.
Two case studies from nearby vertical Wells A and B are described. Well A has a fieldwide unconformity surface picked at a depth of X610 m MD, indicated by a drag pattern in the overlying zone. The carboniferous section in that well is composed of numerous shoaling upward cycles. Any of these cycle tops can act as a vertical permeability barrier and result in a step in the pressure profile. Meanwhile, Well B has an unconformity within the internal Permian at a depth of X142.5 m MD, indicated by the drag pattern. The fieldwide unconformity and a stratigraphic barrier can be proved by a shift of pressure gradient at a depth of X608 m MD, indicated by a change of dip attitude.
Slope Heterogeneity and Production Results in a Steep-sided Upper Paleozoic Isolated Carbonate Platform Reservoir, Karachaganak Field, Kazakhstan
Authors: Katz David A. , Playton Ted , Bellian Jerome , Harris Paul, (Mitch) , Harrison Christopher , Maharaja Amisha 
Published: February 2011

Abstract
Slopes that flank steep, reef-rimmed carbonate platforms are depositionally complex due to a variety of autochthonous and allochthonous deposit types that exhibit vertical and lateral variability. Karachaganak Field, northern Pricaspian Basin, Kazakhstan, is a Permo-Carboniferous isolated carbonate platform with a hydrocarbon column that resides primarily within steep foreslope strata. Historically, the distribution of reservoir properties at Karachaganak has been poorly understood owing to the depositional heterogeneity common in slope environments. These uncertainties were assessed by integrating seismic facies analysis, relevant high-quality outcrop analogues, cores, and log data to produce a detailed depositional model of Karachaganak slopes that predicts compositional and architectural variability. Recent well lookbacks were also performed to assess the impact of carbonate foreslope characterization on well location and design in the current drilling program.
Seismic facies analysis with support from outcrop analogues and forward models reveals depositional regions within stratigraphic intervals that can be further divided into multiple styles of clinoforms, slope and basin sediment wedges, margin configurations, and secondary features (i.e. reentrants). Each of the seismic facies is in turn defined by reflector characteristics, such as continuity, intensity, and geometry. Seismic mapping of the abovementioned elements with corroboration from other subsurface data identifies heterogeneity at well, flow unit, and field scales, including 1) bedset-scale variations internal to clinoforms and wedges, 2) along strike and temporal variations in clinoform or wedge style, and 3) platform-scale asymmetry.
Integration of core and log data, combined with insights from outcrop analogues, allows for prediction of the depositional rock types and depositional regions within the stratigraphy mapped at Karachaganak. Spatial and stratigraphic trends regarding reservoir properties and connectivity are extractable based on the mapped geographic distribution of different clinoform styles, wedge types, and secondary features. Overall, this approach links seismic-scale architecture, petrophysical behavior, and geographic distribution, thereby providing insights for future reservoir development and modeling at Karachaganak. For example, recent production data from the current drilling program shows that wells in the youngest Carboniferous distal slope settings are among the poorest producers due to depositional heterogeneity and disconnected compartments - characteristics that the conceptual model and base case reservoir model predicts. Recent results from wells with trajectories that tatget older slopes are a success and validate both the conceptual geological and reservoir models.
Analysing Pressure Transient Data from Growth Fault Reservoirs in the Niger Delta
Authors: Obera Joseph H. , Peacock Anthony 
Published: February 2011

Abstract
One of the most conspicuous geological features of the Niger Delta is its growth fault pattern. Growth faults are a particular type of normal fault that develops during ongoing sedimentation, so the strata on the hanging wall side of the fault tend to be thicker than those on the footwall side. In this study, a detailed treatment is given of the transient pressure behaviour of a well located near a leaky boundary with unequal formation thickness on opposite sides of the barrier. These types of barriers are typical features of growth fault.
The results of this study generalize previously published works which assumed the thickness index for media on different sides of the fault was zero, one, or infinity. These assumptions are not always valid for growth fault reservoirs commonly found in the Niger Delta. One application of this work would be to facilitate detection of formation thickness on the other side of the fault without drilling a well in that location, this means reduced capital development cost thereby maximizing NPV.
The range of variables examined includes thickness index from zero to one and from one to infinity, also, the effect of transmissibility factor ranging from zero to infinity was included.
Based on this study, it was observed that for high values of the thickness index, the response is similar to that of a constant pressure boundary, while the behaviour resembles the sealing boundary characteristics for low values of the index.
Managing Reservoir Uncertainty in Gas Field Development Using Experimental Design
Authors: Itotoi Ibiada Harrison , Ojeke Akpoebi , Nnamdi Dike , Umurhohwo Jonathan , Benjamin Osaigbovo , AkaChidike Kanu 
Published: February 2011

Abstract
In a new field development, enormous time and energy are put in to identify and quantify both static and dynamic reservoir uncertainties. This could be very challenging when information is limited and not readily available. These data uncertainties vary from project to project depending on the quantity of reliable reservoir data acquired during the exploration and appraisal stage. The first step towards managing reservoir uncertainty in field development is to identify and quantify the key reservoir parameters that affect hydrocarbon in place and recovery. These parameters or factors are so many that their combinational effects result in multiple cases of development options, which will require many simulation runs. Stochastic and statistical data analysis coupled with Experimental Design(ED) have been used in recent times to reduce time and energy expended in managing key reservoir uncertainty parameters.
The case study presented in this paper gives an illustration of a successful ED application in a new gas field development. A detailed workflow was created to identify and quantify the uncertainties and risks in the dynamic model using probabilistic approach. This resulted in Probabilistic field forecasts that were further used to test surface development options in order to determine the optimal field development strategy that is robust to multiple realisations of reservoir uncertainties
A Systematic Approach to Effective Flow Property Determination for Deepwater Heavy Oil Evaluation
Authors: Uzoh O. J. , Ageh E. A. 
Published: February 2011

Abstract
Coarse scale modeling of deepwater turbidites requires that effective properties be developed to capture the fine scale flow behavior. In displacements with unfavourable mobility ratio, displacement instabilities at the shockfront may exist resulting in the occurrence of viscous fingers that reduce breakthrough recovery and increase gas and water production. Viscous fingering effects have been studied and demonstrated by laboratory experiments. The practical scale of fine scale models is usually too large to resolve viscous fingering effects. Hence evidence of viscous fingering has to be tested and appropriate upscaling applied at the fine scale modeling stage.
A two stage upscaling technique has been developed for heavy oil effective flow properties determination, a viscous fingering correction and generation of dynamic pseudos. The viscous fingering correction was done using the method of Clemens and Wit. This assumes that viscous fingers can be described by using a segregated flow approach. Upscaled rock relative permeability for viscous fingering was then used as input into the fine scale modeling. To upscale to the coarse scale model a history matching approach was applied to generate dynamic pseudos.
The application of appropriate effective flow properties to heavy oil characterization improves the quality of the production forecasts, and facilitates proper sizing of facilities.
Equation of State Characterization of a Deepwater Gas Condensate Field with Complex Geochemistry
Authors: Uzoh O. J. , Ageh Eby 
Published: February 2011

Abstract
An 8-component Equation of State 3D model coupled to Petroleum Experts’ GAP has been applied to characterize Deepwatergas field rich gas condensate reservoirs to capture compositional grading and phase behavior effects in the reservoir and production facilities. The Deepwatergas field consists of North and South reservoirs separated by a graben. The North reservoir contains a near-critical gas condensate (CGR of ~ 200 stb/MMscf) with evidence of compositional grading and a speculative oilrim while the South reservoir contains lean condensate (CGR ~ 60 stb/MMscf) with heavy oil and a tar mat at the base of the reservoir. Deepwatergas gas wells (one each in North Reservoir and South Reservoir) are tied back through a 26mile flowline to the host, hence understanding the hydraulics of the subsea flow system was also an important part of the performance evaluation, and key to future performance prediction and re-development decisions.
The results from the study helped explain the producing CGR in the North reservoir, which remained constant below field dew point, and also provided an assessment of gas compression requirements over the producing life of the field.
Improving Deepwater Core Recovery and On-site Handling Through Strategic Coring Protocol
Authors: Nnoaham Ike , Marchall Dave 
Published: February 2011

Abstract
A deep water coring protocol for a turbidite, unconsolidated environment was designed to improve core recoveries and accelerate plug samples needed for routine and special core analysis. The coring protocol was aimed at maximizing recovery by having onsite supervision and prescribing guidelines for WOB, ROP and Flow rate of mud system. It was also designed to facilitate well site freezing, stabilization and plugging using the half moon aluminum liner.
The results from the coring operations clearly demonstrate improved results with significant lessons and areas for improvement. This paper details the learnings and experience encountered during the coring operations.
Locating the Remaining Oil (LTRO) and Delivering Opportunities in a Mature, Declining Oil Field
Authors: Costier Laurent , Mitroshkin Vitaly G. , Hayes Hermélia Mbadinga 
Published: February 2011

Abstract
The Rabi oil field is situated onshore Gabon. It was discovered in 1985 and delivered first oil in 1989. The field reached peak production in 1997 (225 000 bopd) and has since undergone a steep decline (current production ~25 000 bopd).
Using extensive historical surveillance and production data (230+ wells, 70+ still flowing), a "Locate the Remaining Oil" initiative was launched to identify and unlock remaining reserves. A holistic evaluation of the WRM data was used to reach a static model of the fluids distribution, thus moving away from time-consuming, non-unique, full-field dynamic modelling for an oil field the size and the complexity of Rabi.
The updated static model, fluid contact maps for the different sectors and layers of the field alongside volumetric reconciliation helped to identify and locate remaining oil rims and unswept volumes. The LTRO initiative has resulted in an extensive portfolio of infill drilling targets and other activities which can be carried out in existing wells.
To increase the pace of hydrocarbon maturation, low CAPEX interventions such as heel perforations (when oil rims have moved above existing horizontal drains but can still be accessed higher up in the heel of the well) are going through an accelerated maturation process for short-term delivery whilst in parallel, a long-term activity plan focussed on maturing the rest of the portfolio is being developed.
Using Entrepreneurship Development and Corporate Social Responsibility as Strategies for Conflict Resolution in the Niger-Delta region in Nigeria
Authors: Raimi L. , Adeleke I. A. 
Published: February 2011

Abstract
The Niger Delta undoubtedly is the oil fountain of Nigeria. The region comprises of nine oil rich states of Abia, Akwa Ibom, Bayelsa, Cross Riveri, Delta, Edo, Imo, Ondo, and Rivers. The region's oil accounts for approximately 90 percent of the value of Nigeria's exports, but remains one of the least developed regions as a result of deliberate neglect. The neglect of the region for many years by successive governments in Nigeria degenerated into violent political crisis and armed conflict, which began to surge appreciably in the late 1990s and reached a dangerous dimension in 2009. The objective of this paper is to validate the proposal that using entrepreneurship development (ED) and corporate social responsibility (CSR) can be better strategies for conflict resolution (CR) in the Niger-Delta region in Nigeria. Based on the objective of this paper relevant literature on entrepreneurship and corporate social responsibility was reviewed to provide more insights into the various dimensions of the subject matter. More importantly, a survey technique was preferred for the study through the use of structured questionnaire to generate vital information on the topic from 600 Nigerians. The received responses of the respondents were tabulated and systematically analysed with simple frequency table and percentages, while the tentative research hypotheses were tested using Regression and Correlation Analyses. From the data analysis carried out and taking cognisance of the research questions, it was established empirically that entrepreneurship development and corporate social responsibility can be better strategies for conflict resolution in the Niger-Delta. In conclusion, palliative recommendations were given to Fedral Governemnt, policymakers of the multinational oil companies and stakeholders in the oil industry to help forged sustainable peace and energy development in the Niger-Delta.
Experimental and Artificial Neural Network Approaches to Predict the Effect of PVA (Poly Vinyl Acetate) on the Rheological Properties of Water and Crude Oil in EOR Processes
Authors: Rezaian A. , Kordestany A. , Haghighat Sefat M. 
Published: February 2011

Abstract
As consequence of pressure drop in oil reservoirs, production of oil will be difficult and EOR methods are used to improve recovery. In many countries Polyacrylamide is used for polymer flooding in EOR processes, but the problem is that Polyacrylamide is expensive also Acrylamide needs to be handled using best laboratory practices (such as having safe systems of work and wearing appropriate gloves, lab coat etc.) to avoid poisonous exposure since it is a neurotoxin.
In this paper, it is intended to investigate the effect of PVA (Poly Vinyl Acetate) on rheological properties (such as viscosity) of crude oil, water, and their mixture and see if it is possible to use this polymer in order to enhance oil recovery. Our objective is to determine the minimum amount of polymer to increase the viscosity of water and decrease the viscosity of crude oil simultaneously. Since even a small change of polymer amount requires extra costs, and experimental investigation of small polymer volume change could be time-consuming, an artificial neural network is developed to estimate polymer volume percentage.
Some of the experimental data used to test the network that showed a close agreement. Using 15 percent of polymer as optimum amount, 7.5 bbl of polymer is needed to recover 100 bbl oil. One should bear in mind that the polymer used here is not pure. If we could use pure polymer it may decrease the amount of polymer so the costs will decrease considerably.
Since this polymer is shear thickener for water, is not exorbitant in comparison to Polyacrylamide, and not biologically degraded, it could positively affect oil recovery under slow shear stresses.
Validating Reserves Estimation From A Simple Analytical Methodology with a Full-field 3D Model in a Giant Brown Reservoir
Authors: Sonde Adenike , Aboaja Ugochukwu , Oghene Ufuoma , Coker Trudy , Osho Rotimi 
Published: February 2011

Abstract
This paper presents the results of a 3D model constructed for a giant, densely faulted reservoir in one of the biggest fields in the Niger Delta. The study also showcases how simple analytical techniques applied in a technically thorough manner can achieve close or similar results to those from a calibrated 3D simulation model.
In carrying out this work, a detailed 3D model was built and calibrated for a very mature reservoir; incorporating results of the recently drilled wells in the field, revalidated integrated data and latest historical performance data. The reservoir, which is densely faulted by a conjugate system of synthetic and antithetic faults, is the largest in the field accounting for almost half of the field's resource volumes. The large number of NW-SE faults, coupled with the relatively high offtake rates from the reservoir, have throttled the activity of the otherwise infinite aquifer and led to severe pressure depletion in the reservoir. Consequently, a lot of the producers quit at relatively low water cuts (~40 − 50%). One of the objectives of the detailed modelling study was to investigate the benefits and gains of gaslifting existing and future new wells. Prior to this study, simple decline curve analysis (DCA) had been carried out independently on a well-by-well basis using estimated abandonment conditions under gasliftassisted flow to predict the recoveries and gains from gaslifting.
The prediction results from the full-field calibrated model compare very closely with the estimates from the individual wells DCA's and suggest that the DCA results can be used as 50/50 estimates for other reservoirs in the field where there are no full 3D models. This work therefore supports the fact that simple analytical methods, which are applied in a technically thorough manner, can still be used in the absence of full 3D models.