bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental and Simulation Of CO2-Foam Flooding In Fractured Chalk Rock At Reservoir Conditions: Effect Of Mode Of Injection On Oil Recovery
Authors: John Zuta , Ingebret Fjelde , Roman Berenblyum 
Published: July 2010

Abstract
Field trials and laboratory tests of CO2-foam have shown some success. A number of CO2-EOR field trials with either miscible or near miscible gas injection have shown that foam can lower the mobility of CO2 and improve the macroscopic sweep efficiency. However, not much work about CO2-foam flooding in fractured chalk reservoirs with low matrix permeability have been published in the literature. During CO2-foam flooding of fractured chalk media, it is expected that the injected fluids will flow in the high permeability fractures where foam will preferentially be formed. This will increase the local resistance to flow and divert more of the CO2 and CO2-foaming agent solution into the low permeable matrix.
This paper presents results from laboratory experiments and simulation studies carried out to investigate the effect of mode of injection on oil recovery during CO2-foam flooding of water flooded fractured chalk models at reservoir conditions. The fractured model was created by drilling a hole through the centre of the plug and homogeneously packing it with glass beads. The CO2-foam process was conducted by injecting pre-formed foam either horizontally or vertically into the fractured models at 340 bar and 55°C. Pure CO2 and WAG processes were also carried out on similar fractured models to establish base case behaviours at the same conditions.
Laboratory results show that additional oil after water flooding is recoverable by injecting pre-formed foam either horizontally or vertically (from the top) in the CO2-foam processes when compared to the injection of pure CO2 and CO2-WAG at the same effective permeability and CO2 volume. In the simulation studies carried out with CMG's compositional reservoir simulator STARS on a similar fractured model used in the laboratory experiments, the results from the core floods were quantitatively confirmed. Additional simulation carried out in large matrix blocks on the field scale showed that CO2-foam can recover additional oil at reservoir conditions. However, the adsorption of the foaming agent can make the CO2-foam process inefficient.
Anti-corrosion Technique of Injection Well In CO2 Flooding
Authors: Fuzhou Wan , Gao Chunliang , Yu Lei 
Published: July 2010

Abstract
CO2 gas has low viscosity, flows very freely and is corrosive. This paper presents two innovative and economical anti-corrosion techniques of injecting (flooding with) CO2 under conditions of high temperature, high pressure and the CO2 cause corrosion. The down hole packer was fabricated with the CO2 corrosion resistant chrome-plated alloy steel. Chromium is one of the most hard metal and corrosion resistant material, the equipments and devices down hole were chrome-plated that can be also wear-resistant effect. and the general rubber design. The casing tubing annulus injected the imidazoline type corrosion inhibitor to keep the pressure balancing, anti-corrosion situation to protect tubing pipes and casing pipes. This anti-corrosion technique of injection well in CO2 flooding ensured the packer seal long-term security and achieved the CO2 gas safety injection.
Performance and Economic Evaluation of Cyclic Pressure Pulsing in Naturally Fractured Reservoirs
Authors: Artun E. , Ertekin T. , Watson R. , Al-Wadhahi M. , Miller B. 
Published: July 2010

Abstract
Gas cyclic pressure pulsing is an effective EOR method in naturally fractured reservoirs. A limited number of studies concerning this method in the literature focuses on specific reservoirs and the optimum operating conditions have not been broadly investigated. In this study, we present a detailed parametric study of the process from both operational and reservoir perspectives. Incremental oil production, peak oil rate and net present value (NPV) are considered as the important markers for the performance criteria. The necessary analyses are performed for a single-well, dual- porosity, compositional reservoir model. In the first part of the study, parametric studies are conducted to develop a better understanding of the operational parameters affecting the process performance, in the shallow, naturally fractured, and depleted reservoirs of Big Andy Field in Eastern Kentucky. These include analyses of various design parameters such as soaking period, cycle rate limit, number of cycles, cycle and cumulative injected gas volumes. In the second part of the study, reservoir characteristics are investigated. Comparative discussions are presented between cases with CO2 and N2 as the injected gas on reservoir fluids of different compositions (heavy, black and volatile oils). Influences of area, thickness, fracture/matrix permeabilities, initial reservoir pressure and temperature on the process are studied. It is observed that N2, as a lower-cost gas, would be a better choice than CO2 in the Big Andy Field. With the oil price used in this study, the cost of injected gas becomes relatively insignificant in economic considerations. Increased income due to increased oil production overcomes the increased costs with higher volumes of gas. The way reservoir characteristics affect the process performance is very similar in cases with CO2 and N2, but differs significantly in different reservoir fluids. Thicknesses ranging between 20 and 50 ft produced more favorable results. A higher efficiency was observed with smaller drainage areas (5-8 acres) in the presence of heavy oil. For the cases with volatile and black oil, it is seen that the process efficiency is not significantly altered by the area. The phase behavior of the reservoir fluid is very important for the performance of the process. Initial pressure/temperature of the reservoir, and therefore, the initial fractions of gas/liquid phases affect the process efficiency in a more pronounced manner.
Modeling of Transport of a CO2-Foaming agent during CO2-Foam Processes in Fractured Chalk Rock
Authors: John Zuta , Ingebret Fjelde , Roman Berenblyum , Vartdal Leif Hogne , Henrik Ovesen 
Published: July 2010

AbstractIn fractured chalk reservoirs with low matrix permeability, molecular diffusion and retention of the foaming agent will control the transport of the foaming agent solution from the fracture into the matrix as well inside the matrix. However, the transport of CO2-foaming agents and how much of the matrix will be contacted by the CO2-foaming agent in fractured chalk reservoirs has not been investigated.This paper presents both experimental and numerical simulation studies performed to investigate the transport of a CO2-foaming agent from a fracture into an outcrop chalk core plug at two different temperatures; room temperature and 55°C. Plugs with different water saturations were used; Sw=100%, Sorw (20-30%) and Swi (14%). The fracture was created by transferring plugs with different diameters into cylinders with an annulus space around the plugs. The fracture volumes were filled with different initial concentrations of CO2-foaming agent solutions. The experiments were monitored by taking fluid samples from the space above the fracture at different times until constant foaming agent concentration in the fractures. At different exposure times, the plugs were demounted and samples taken from the outer, middle and centre portions along the whole lengths of the plugs. These samples were analysed for foaming agent concentration to determine the transport rate in the matrix.Results indicate that the transport of the foaming agent solutions into the plugs depend on the diameter of the plugs, temperature and amount of oil remaining in the plugs. The transport of the foaming agent solution from the fractures into the plugs was also modelled with the CMG's commercial reservoir simulator STARS. A good match between experimental and modelling results was obtained. Based on simulated results, the foaming agent was also observed to penetrate and reach the middle sections of the plugs with and without oil. Additional simulation results show that on the field scale, the transport of the foaming agent will depend on the size of the matrix blocks, rock type, and adsorption of the foaming agent as well as the presence of oil.
Managing Field Development Uncertainty in the Geologically Complex Stringer Sands in Offshore Saudi Arabia
Authors: Warren Phillip B. , Al-Ghamdi Faisal A. 
Published: July 2010

Abstract
This paper will describe how new technologies, such as geosteering, seismic imaging and new drilling techniques, are being pursued to improve overall net sand reservoir contact and production improvements in horizontal wells. These technologies have been implemented in offshore wells to obtain valuable geological information, improve well placement, and minimize sidetracks by reducing uncertainty. The geologically complex stringer sand reservoir is unconsolidated sandstone with a permeability of 3-5 Darcy. Proper well placement and minimizing costly sidetracks are critical to the success of this offshore field.
Improvements in the well placement of horizontal wells within stringer sand reservoirs have improved immensely in the offshore fields of Saudi Arabia. New technologies and techniques involving geosteering, seismic imaging, and well design have been evaluated and field tested, and has improved the net to gross sand ratio from 50% to over 80% with a corresponding increase in production of over 50%, with opportunities for additional improvement.
Design and Implementation of the First CO2-EOR Pilot in Abu Dhabi, UAE
Authors: Al Hajeri Salma , Negahban Shahin , Al-Yafei Ghaniya , Al Basry Ali 
Published: July 2010

Abstract
Carbon Dioxide (CO2) Enhanced Oil Recovery (EOR) process is most likely to become the preferred hydrocarbon recovery process in future in Abu Dhabi. The complexity and cost of implementing large scale EOR projects require the development of a detailed EOR strategy, clearly defined targeted objectives, a visionary work-plan (roadmap) and staged evaluation prior to full field commercial implementation. Abu Dhabi Company for Onshore Oil Operations (ADCO) is in the process of conducting the first Middle-East CO2-EOR pilot in an onshore complex carbonate reservoir.
This paper discusses the design and implementation of the first ADCO CO2-EOR Pilot Project which addresses key technical and business uncertainties and risks associated with CO2 injection in ADCO reservoirs in the future. The pilot was considered the best approach to evaluate feasibility of this EOR approach on a field scale in addition to other verifications through laboratory and simulation studies.
The project started with a company-wide screening study which attempted to identify both the most appropriate EOR option for ADCO reservoirs and the best reservoir candidates. Subsequently, an in-house simulation study was conducted to confirm the best identified candidate reservoir. The Roadmap defined studies required to fill the required data gaps. Advanced CO2-PVT, Asphaltene and SCAL studies were conducted to reduce the uncertainties related to CO2 injection. The pilot objectives and constrains were clearly defined at the early stage of the project. Challenges of obtaining the required CO2 volumes for injection were overcome.
A history matched compositional reservoir simulation model was used as an effective tool to design and optimize the pilot. Sufficient time and effort were expended in the pilot design and optimization in order to meet the implementation objectives in a timely manner. These include drilling of the wells, construction of the surface facilities, development and execution of the surveillance and monitoring plan and finally the operation of the pilot.
This paper outlines the design and implementation of the first ever Middle-East CO2-EOR pilot in an On-shore complex carbonate field in Abu Dhabi, UAE.
A Comprehensive Kinetic Theory to Model Thermolysis, Aquathermolysis, Gasification, Combustion, and Oxidation of Athabasca Bitumen
Authors: Kapadia Punitkumar R. , Kallos Michael S. , Gates Ian D. 
Published: July 2010

Abstract
Extraction and upgrading of bitumen in Alberta, Canada uses large amounts of energy, generates huge volumes of acid gas, consumes massive volumes of water, and is costly. Most bitumen produced in Alberta is converted in surface upgraders to synthetic crude oil (SCO), a 31 to 33°API oil product. Next, SCO is converted to transportation fuels and lubricants in conventional refineries. Bitumen upgrading requires hydrogen. Today, most of the hydrogen is produced by steam reforming of methane which requires huge amounts of methane. Alternatively, hydrogen can be generated by in situ gasification of bitumen. Gasification is potentially more energy efficient with reduced emissions since acid gases are sequestered to some extent in the reservoir. Also water usage is lowered and heavy metals and sulfur compounds in the bitumen tend to remain downhole. The overall objective of this research is to understand and optimize hydrogen generation from bitumen reservoirs. In situ technologies that convert bitumen to hydrogen will have direct application in bitumen upgrading, use as feedstock for ammonia and other chemicals, and may be a key step to start a hydrogen economy. One key step towards the design of in situ hydrogen generations processes is the construction of the reaction scheme together with the associated kinetic parameters. Here, a unified kinetic model that takes pyrolysis (thermolysis, thermal cracking), aquathermolysis, gasification, and combustion (oxidation) of Athabasca bitumen has been assembled. The model has been calibrated against 7 experimental and plant data sets (with 149 data points in total) and implemented in a thermal reservoir simulator. The unified kinetic model was developed by performing a global match of the reaction scheme and kinetic parameters against all available pyrolysis, aquathermolysis, gasification, combustion, and oxidation data.
Surfactant-Induced Spreading and Wettability Effects in Condensate Reservoirs
Authors: Zheng Y. , Rao D. N. 
Published: July 2010

Abstract
Condensate blockage is known as a serious problem in gas condensate reservoirs due to the depletion of reservoirs to pressures below the dew point. It reduces gas phase relative permeability and consequently results in the loss of gas productivity. The objective of this study was to identify and attempt to remedy this blockage problem through reservoir wettability determination and wettability alteration by using surfactants in the condensate buildup regions. Experiments were performed at ambient conditions by using stock tank condensate sample, methane, synthetic reservoir brine, and quartz substrate.
In this study, both the spreading coefficient and wettability were measured to characterize the influence of anionic and nonionic surfactant on interfacial behavior. The contact angles were experimentally measured using Dual-Drop-Dual-Crystal (DDDC) technique. The Drop Shape Analysis (DSA) and capillary rise technique were used for measuring oil-water, watergas and gas-oil interfacial tensions. An advancing angle of 152° obtained from the experiments indicated that this sandstone condensate reservoir had a strong oil-wet nature. Anionic and nonionic surfactants at the concentration levels of 500, 1500, and 3000 ppm were tested in the experiments. Results showed that although spreading coefficients were all positive for the condensate-brine system with/without surfactants, they decreased after the surfactants application. This implies that oil recovery is still enhanced from surfactants usage in this strongly oil-wet system. Also, all three concentrations of anionic surfactant were shown to alter the wettability of quartz surface from strongly oil-wet to intermediate-wet or weakly oil-wet. However, no wettability alteration was found after nonionic surfactant usage. The key finding from the ambient condition experiments is that the sandstone reservoir wettability is altered from strongly oil-wet to intermediate-wet or weakly oil-wet by using an anionic surfactant.
Surfactant Systems for EOR in High-Temperature, High-salinity Environments
Authors: Puerto Maura , Hirasaki George J. , Miller Clarence A. , Barnes Julian R. 
Published: July 2010

ABSTRACT
A systematic study was made of phase behavior of alkoxy glycidyl sulfonates (AGSs). These surfactants were screened with either NaCl-only brines or NaCl-only brines and n-octane at WOR ~1 for temperatures between approximately 85°C and 120°C. All test cases were free of alcohols and other co-solvents. Classical Winsor phase behavior was observed in most scans with optimal salinities ranging from less than 1% NaCl to more than 20% NaCl for AGSs with suitable combinations of hydrophobe and alkoxy chain type (ethylene oxide or propylene oxide) and chain length. Oil solubilization was high, indicating that ultralow interfacial tensions existed near optimal conditions. The test results for 120°C at WOR~1 have been summarized in a map, which might provide a useful guide for initial selection of such surfactants for EOR processes. Saline solutions of AGSs separate at elevated temperatures into two liquid phases (cloud point phenomenon), which may be problematic when they are injected into high-temperature reservoirs. An example is provided which indicates that this situation can be alleviated by blending suitable AGS and internal olefin sulfonate (IOS) surfactants, these being within Shell Chemical's ENORDETTM range of surfactants for EOR. Synergy between the two types of surfactant resulted in transparent, single-phase aqueous solutions for some blends, but not for the individual surfactants, over a range of conditions including in synthetic seawater. Such blends are promising because both AGS and IOS surfactants have structural features that can be adjusted during manufacture to give a range of properties to suit reservoir conditions (temperature, salinity and crude oil type).
History Matching Channelized Reservoirs Using Reversible Jump Markov Chain Monte Carlo Methods
Authors: Xie Jiang , Mondal Anirban , Efendiev Yalchin , Mallick Bani , Datta-Gupta Akhil 
Published: July 2010

Abstract
A novel method is presented for history matching and uncertainty quantification for channelized reservoirs using Reversible Jump Markov Chain Monte Carlo (RJMCMC) methods. Our objective is to efficiently sample realizations of channelized permeability fields conditioned to production data and permeability values at the wells.
In our approach, the channelized permeability field is reparameterized using the discrete cosine transform (DCT). The parameters representing the channel structure are the coefficients in truncated frequency domain. The parameter space is searched using a RJMCMC, where the dimension of the parameter space is assumed to be unknown. For each step of the RJMCMC, the dimension of the uncertainty space can be increased or decreased according to a prescribed prior distribution. This flexibility in the parameter dimension allows an efficient search of the uncertainty space. To speed up the computation and improve the acceptance rate of the RJMCMC algorithm, we employ two-stage methods whereby coarse-scale simulations are used to screen out the undesired proposals. After simulations, multi-dimensional scaling and cluster analysis are used to select realizations from the accepted models to adequately represent the diversity of the models.
We demonstrate the effectiveness of the RJMCMC algorithm using both 2D and 3D examples involving waterflood history matching. The 2-D example shows that the RJMCMC algorithm can successfully match the data and identify the orientation of the channels in the reference model. The 3-D results show that the proposed algorithm can determine the large-scale features of the reference channelized permeability field based on the production data. The MCMC algorithms naturally provide multiple realizations of the permeability field conditioned to well and production data and thus, allow for uncertainty quantification in the forecasting.
On the Relationship between Completion Design, Reservoir Characteristics, and Steam Conformance Achieved in Steam-based Recovery Processes such as SAGD
Authors: Wei Wei , Gates Ian D. 
Published: July 2010

Abstract
With continuing decline of conventional crude oil reserves, there is higher demand for developing and producing heavy oil and bitumen resources. In Alberta, Canada, there are over 170 billion barrels of recoverable bitumen in oil sands. The two main thermal technologies being used to produce are Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS). For Athabasca reservoirs, SAGD is the method of choice since the oil has low solution gas. One key factor that controls the success of these methods is steam conformance – the ability to control the distribution of steam within the oil column. In this research, thermocouple data from the Surmont SAGD pilot project together with reservoir geology are analyzed to examine steam conformance and its impact on process performance (oil rate, recovery factor, and steam to oil ratio). The data is analyzed to generate a simple correlation between reservoir geology and operating pressure to predict vertical steam conformance versus time. The results demonstrate that the reservoir geology, operating pressure, and well completion design all affect steam conformance in the reservoir. Also, the distribution of steam flow and pressure within the well impacts steam conformance in the reservoir. An analysis of the A wellpair of the Surmont SAGD pilot suggests that the distribution of steam flow in the well contributes largely to the non-uniform steam conformance along this wellpair.
The Displacement of Heavy Oil From Diatomite Using Hot Water and Steam
Authors: Dietrich J. K. 
Published: July 2010

Abstract
Results of diatomite core displacement tests designed to study the effects of fluid system, rock type, stress and temperature are presented here. Two heavy oils (12.3 and 17.8°API) were evaluated using water varying in temperature from 91 to 550°F and steam at either 330 or 550°F. Three amorphous Opal-A and 1 crystalline Opal-CT rock types were tested at effective stress levels varying from 450 to 1100 psi. Measurements are provided for both dead and live-oil density and viscosity, live-oil thermal expansion, and remaining oil saturation as a function of temperature and fluid displacement type and phase.
Hot-water flooding at about 200°F as compared to 100°F was shown to be capable of increasing oil displacement efficiency from about 30 to 60% of original oil-in-place. Hot-water flooding at either 330°F or 550°F was shown to be capable of further increasing displacement efficiency to about 70% of OOIP, with the higher temperature water providing only marginally improved recovery. Steamflooding at 550°F was shown to be capable of recovering more than 80% of OOIP and was much more efficient than the 330°F steamfloods. The lowest residual oil saturations and highest displacement efficiencies were consistently measured for rock type "C", a dirty Opal-A found in prior published research to be the most compressible of the various rock types.
Counter-current imbibition (CCI) of water and oil is considered to be a key mechanism in the published research performed to understand the effects of hot fluid injection in diatomite, where core samples were purposely tested at low effective stress levels to minimize the effects of compaction. Laboratory-measured displacement efficiencies are presented here for stress and temperature levels typical of field conditions, where the primary diatomite pore structure is radically altered and the diatomite skeletal material is crushed by thermally-induced compaction. Under these field conditions, displacement efficiencies are surprisingly high for hot fluid injection processes in diatomite, particularly for hot-water flooding. The remaining oil saturation data are applicable in numerical modeling studies, and differences in oil displacement efficiency by rock type highlight the need to use different geological facies when building geo-cellular models of diatomite reservoirs.