bluuebunny/crossref_metadata_2025_split huggingface dataset:
Moving CO2 EOR Offshore
Authors: Goodyear S. G. , Koster M. P. , Marriott K. A. , Paterson A.. , Sipkema A. W. , Young I. M. 
Published: July 2011

AbstractCO2 can be an effective EOR agent and is the dominant anthropogenic greenhouse gas driving global warming. Capturing CO2 from industrial sources in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future, by adding value through EOR production and field life extension, and providing long term secure storage post-EOR operations.Shell is working to implement new generation CO2 projects, including offshore applications. Based on recent offshore project design experience, this paper describes the challenges in moving CO2 EOR from onshore to offshore and the solutions developed, in the key areas of safety, facilities, wells, subsurface and piloting. The overriding design principle in any project is HSE. Offshore operations brings a new set of challenges over inventory, pressure, confined spaces and evacuation, with conventional emergency procedures requiring modification because of the different physical characteristics of CO2 releases compared to hydrocarbon gas. Surface facilities need to be simple to minimise CAPEX, weight and space while maintaining flexibility, since there is less scope to incrementally evolve the surface facilities as is the case onshore. Balancing the tension between these objectives requires very close surface and subsurface integration to find optimal and cost-effective solutions. This is illustrated with three key decision areas: gas treatment options for back produced CO2 and hydrocarbon gas, artificial lift and facilities capacity.A novel integrated CO2 gas lift system is described. This simplifies facilities and reduces CAPEX and OPEX, while at the same time providing a high degree of flexibility and risk management over the EOR life cycle in terms of subsurface uncertainty and reducing the issues around molecular weight variation in the recycled gas and the degree of turndown required in the facilities in the early years of EOR operations.
Simulation Study of Enhanced Gas Recovery Process Using a Compositional and a Black Oil Simulator
Authors: Rafiee M. M. , Ramazanian M.. 
Published: July 2011

Abstract
Enhanced Gas Recovery (EGR) is a way of producing residual gas in depleted gas reservoirs. CO2 injection is a promising method for EGR by increasing the reservoir pressure and also gas-gas displacement. The miscibility of injected CO2 and residual gas in place is an important factor in this process.
The objective of this work is to investigate the miscibility process of CO2 injection into gas reservoirs using a compositional and a black oil reservoir simulator. A synthetic simulation model is built for this process having injection and production wells. The effect of gas miscibility is studied for both simulators and the results are compared to find optimum miscibility parameters.
The simulation results show that compositional result is similar to the black oil run, when the miscibility factor in the later case is almost half of the complete miscible process. In case of no miscibility the extension front is very sharp while for the case of complete miscibility the CO2 front is more advanced toward production well with wider length of miscible zone.
The findings of this paper could be beneficial for further pilot and field case study for monitoring of the observation and abandonment wells. Also the method is helpful in using black oil simulator as an alternative, less working effort and same reliable for CO2 sequestration in comparison to a compositional simulator.
Large Scale CO2 Flood Begins Along Texas Gulf Coast
Authors: Davis Darrell , Scott Mark , Roberson Kris , Robinson Adam 
Published: July 2011

Abstract
CO2 flooding of a strong waterdrive reservoir has begun along the Texas Gulf Coast. Ninety (90) million SCF of CO2 will be injected daily during 2011 to re-pressure the reservoir and rates as high as 1 billion SCF per day (including recycle) will ultimately be used to develop this giant oil field. Design of this CO2 flood at a depth of 6,000 feet has focused upon pattern design, operating pressure, and the impact of aquifer influence. Success of CO2 floods, hinges upon the ability to increase reservoir pressure to, or near, miscibility pressure and to effectively sweep the reservoir. Laboratory and field performance data have been utilized to improve the design of this continuous CO2 injection project.
Some of the largest oil reservoirs in the world are composed of high permeability sandstones with large aquifers. These reservoirs are attractive candidates for CO2 flooding due to the size of the initial oil deposits; however recoveries due to the strong waterdrive and good quality sands often result in low residual and/or remaining oil saturations. With oil zone thickness often exceeding 100 feet, significant challenges exist in developing optimum completion strategy and pattern selection. For the Hastings CO2 flood, five-spot injection patterns will be staggered so that the upper and lower portions of the reservoir have dedicated injectors and producers, thus improving vertical sweep. Water injection profiles have also shown that perforation shot density is key to insuring uniform vertical sweep given the minimal pressure drop across each perforation when low viscosity CO2 is injected. Reservoir pressure within the floodable area must also be maintained (preventing leakoff) in order to maximize displacement efficiency. This is accomplished by use of water injection wells placed downdip to act as a water curtain, thus reducing leakoff of pressure into the infinite acting aquifer. As expansion of the EOR project develops additional patterns downdip, water injectors will be placed further downdip, while the updip injectors will be placed on CO2.
Optimization of Solvent Additive SAGD Applications using Hybrid Optimization Techniques
Authors: Al-Gosayir Muhammad , Babadagli Tayfun , Leung Juliana 
Published: July 2011

Abstract
Heavy oil and bitumen recovery cost is excessive mainly due to high energy requirement to generate heat and its environmental impacts. Steam Assisted Gravity Drainage (SAGD) is an example of this case; the determination of optimal operating conditions, such as injection rates and well locations, based on reservoir and fluid characteristics is essential in the design of field applications.
Many Steam Assisted Gravity Drainage (SAGD) optimization studies published in the literature combined numerical simulation with graphical or analytical techniques for design and performance evaluation. There have been limited efforts that integrated the simulation exercise with global optimization algorithms. Some studies focused on optimization of cumulative steam-to-oil ratio (cSOR) in SAGD by altering steam injection rates, while others focused on optimization of cumulative net energy-to-oil ratio (cEOR) in solvent-additive SAGD by altering injection pressures and fraction of solvent in the injection stream. Typical scoring functions were the net present value per hectare of land (NPV/ha) by controlling steam and solvent rates. Several studies also considered total project net present value calculation by changing total project area, capital cost intensities, solvent prices, discount rate, and risk factors to determine the well spacing and drilling schedule. Optimization techniques commonly used in those studies were scattered search, simulated annealing, and genetic algorithm (GA). However, applications of hybrid genetic algorithm were rarely found.
In continuation of these efforts, we focused on optimizing the SAGD process and its extension to solvent-additive SAGD using hybrid genetic algorithm. The objective function was defined to obtain the lowest cumulative steam-oil ratio (cSOR) and highest recovery factor. It was used later as scoring function by changing operating pressure, solvent-to-steam ratio, and steam injection rates. The results in this paper can be implemented directly in the efforts of minimization of cost and environmental impacts while accelerating the recovery in SAGD.
Performance Study of a New Type Alkaline/Surfactant/Polymer Ternary Complex
Authors: Liu Yong , Lu Yi , Lin Weimin , Hu Xingqi 
Published: July 2011

AbstractNaOH, which is used in traditional Alkaline/Surfactant/Polymer Flooding technique, can result in formation damage and equipment corrosion1, 2. In order to replace NaOH with Na2CO3, a new type Gemini surfactant-DEDS is synthesized. Its dose is very lower than traditional surfactant for ASP combination flooding. Rheological behavior of DEDS/AP-P4/Na2CO3 (ASP) aqueous solution and the effect of salt on it were studied. Conclusions are as follows: DEDS has the same influencent as inorganic electrolyte, and rheological behavior of ASP aqueous solution can be described with power law fluid mode. The apparent viscosity of ASP aqueous solution (AP-P4 2000mg/L, Na2CO3 1%, DEDS 0.423mmol/L and NaCl 1×104mg/L) is 3.88–8.11 that of ASP aqueous solution (AP-P4 2000mg/L, Na2CO3 1%, DEDS 0.423mmol/L), Rheological behavior of ASP solution exhibits a little character of Bingham fluid with the increasing of NaCl concentration. When DEDS concentration is 0.423mmol/L, and AP-P4 concentration is 1500mg/L, ASP ability emulsifing analog oil will enhance with the increasing of Na2CO3 concentration. When Na2CO3 concentration reaches 1%, ASP solution and analog oil is completely emulsified, IFT reaches 10−4mN/m, and ultra-low IFT is realized. Using ASP solution to drive homogeneous test core undergoing waterflooding, recovery efficiency increases about 18%; for nonhomogeneous test core, which permeability contrast is 1.76, its increment of tight permeability is more 6.8% than of high permeability, and ASP solution possesses better profile control property. In comparison with traditional surfactants, DEDS dosage can remarkably decrease, and weak alkaline ASP flooding can be achieved. Extent of formation damage and equipment corrosion of chemicals will obviously reduce, when it is used in field.
A Novel Alkaline-Surfactant-Foam EOR Process
Authors: Guo Hua , Faber Rien , Buijse Marten , Zitha Pacelli L.J. 
Published: July 2011

AbstractThis paper reports a laboratory study of a novel alkaline-surfactant-foam (ASF) process. The goal of the study was to investigate whether foaming a specially designed AS formulation could meet the two key requirements for a good enhanced oil recovery (EOR), i.e. lowering the interfacial tension (IFT) considerably and ensuring a good mobility control. The study included phase behavior tests, foam column tests and CT scan-aided core-floods. It was found that the IFT of the designed alkali-surfactant (AS) and a selected crude oil drops by four orders of magnitude at the optimum salinity. The AS proved to be a good foaming agent in the column tests and core-floods in absence of oil. The mobility reduction due to the AS foam was hardly sensitive to salinity and increased with decreasing foam quality. CT scanned core-floods demonstrated that AS foam following a small AS pre-flush recovered almost all the oil left after water-flooding. The oil recovery mechanism by ASF combines the formation of an oil bank and the transport of emulsified oil by flowing lamellae. Further optimization of the ASF is needed to ensure that the oil is produced exclusively by the oil bank.
Carbon Capture for Enhanced Oil Recovery in Niger Delta: A Case Study of Okota/Okpoputa Field in Offshore Niger Delta
Authors: Odesa David , Adewale Dosumnu 
Published: July 2011

Abstract
Carbon capture for enhanced oil recovery is a proven technology that holds the promise of increasing oil reserves, reducing greenhouse gas (GHG) emissions, diminish the concerns associated with the release of cocktail gases from gas flaring and reduce hostility in host communities. In this work, we considered the Okota/Okpoputa field in Offshore Niger Delta and covered areas of interest such as the post combustion capture using monoethanolamine (MEA), prognosis of storage site, increase production pressure, economics of the capture and assessment of the risk of leakage. With about 80 million tonnes of CO2 captured annually from flared flue gas, the CO2-enhanced oil recovery will yield 20–40% Original Oil in Place (OOIIP), and this will translate to a savings of $ 474,500,000 excluding commercial sales of CO2.
New Approach to Upgrade the Combustion In Situ Process by using an Emulsified Additive on Heavy Oil from Orinoco Belt
Authors: Arturo J.. , Mendoza R.. , Oliveros Deivi , Arellano Dixon , Perozo Héctor , Reinoza Jefferson , Rivas Ángel 
Published: July 2011

AbstractThe main challenge of the Venezuelan Oil Industry is focused in exploitation of the Orinoco Oil Belt (FPO), where potentiality are located the largest heavy oil reserves in the world. The heavy and extra heavy oil reservoirs are produced by its primary energy in some cases; in others depending on the oil viscosity enhanced oil recovery by thermal processes are applied. In Situ Combustion has been studied for more than four decade and there are reported several studies using additive in order to optimize it. However, a wide range of kind of additive has been studied and they evidence an increase of the recovery associated and upgrading to the oil produced.The present approach has been visualized as a considerable opportunity to contact a bigger zone into the reservoir and major effectiveness of the reaction promote. In that sense, PDVSA Intevep is focused on optimizing the combustion process using non-conventional additive. The methodology used is based on the air injection into the reservoir and posterior heating for ignition, where the combustion front will face with the emulsified additive promoting a series of exothermic oxidation reactions which reduce oil viscosity, due to the additional energy generated by the presence of additive in the system. The results obtained in the combustion tests, showed front stability, a considerable increase in the reactions conversion, reduction of oil viscosity, an as a consequence major oil recovery and oil value for the marketing.
Production Optimization at Connacher’s Pod One (Great Divide) Oil Sands Project
Authors: Johnson M. D. , Hansen L. A. , Lau T.. , Phenix T. J. , Breen S. P. 
Published: July 2011

Abstract
Connacher’s first oil sands project, the Pod One facility at Great Divide, has been operational since 2007. The successful SAGD project has produced approximately 7 million barrels of bitumen. During the past three and a half years, the impacts of certain predicted reservoir challenges and opportunities have become apparent.
While the quality of the oil sands in this first phase of Pod One is generally good, Pad 101 South in particular has geological zones that affect SAGD operation. This includes a bitumen lean zone, and a gas cap overlying the main bitumen channel/s. Early field results matched with detailed simulations have shown positive results in maximizing well pair production. For the purposes of this paper a lean bitumen zone differs from an aquifer in two ways. The lean zone is not charged, and is limited in size. The operation is also complicated by the fact the gas bearing zone has been depleted through earlier production.
Connacher’s operating practice at Great Divide attempts to achieve a pressure balance between the 3 zones (rich oil sands, lean zone, gas cap) to reduce steam loss and maximize production rates. Reducing the pressure encourages steam chamber development growth horizontally and ensures that steam contacts the highly saturated bitumen areas. How this is achieved with the highest positive impact on well productivity is illustrated with operational data and analysis including the results of simulations that recommended the optimum operating strategies.
Improved Characterization of EOR Processes in 3D. Characterizing Mineralogy, Wettability and Residual Fluid Phases at the Pore Scale
Authors: Knackstedt Mark , Senden Tim , Carnerup Anna , Fogden Andrew 
Published: July 2011

Abstract
At the conclusion of flooding into an oil- or gas-bearing reservoir, a significant fraction of the original hydrocarbon in place remains as trapped residual phase. In addition to determining the amount of trapped phase, the microscopic distribution within the pore space of the reservoir rock is important to gain a better understanding of recovery mechanisms, and for the design and implementation of improved or enhanced recovery processes. While the importance of the mineralogy, wettability, pore scale structure and distribution of residual oil is widely acknowledged, little quantitative information on these properties has been directly available. We describe results from an ongoing interdisciplinary study of this problem bridging the molecular-scale, pore-scale and core-scale of rock structure using surface chemical techniques, pore scale x-ray microtomographic imaging, petrographical imaging and experimental analysis on reservoir carbonate material. We first describe the experimental techniques used in this study and review the registration technology which enables one to quantify mineralogy on 3D images through the integration of SEM-EDS with micro-CT methods. We then discuss methods to visualize pore scale oil and brine populations at the pore scale with a particular focus on characterizing native state plugs. In parallel, we characterize the physical and surface chemical characteristics of rock surfaces at the pore-scale and sub-pore scale, and consider the oil-brine-rock interactions giving rise to these states. This interdisciplinary approach provides the foundation for understanding recovery processes and for the development of strategies to alter wettability and improve recovery in reservoirs.
Using Core Data to Study and Optimize the Completion Strategy in EOR Operations
Authors: Nagineni Venu Gopal , D’Souza David F. , Holden Charles , Hughes Richard G. 
Published: July 2011

Abstract
Dykstra Parsons Coefficients and Lorenz Coefficients calculated from core data are traditionally used as indicators of heterogeneity in a reservoir. Modified Lorenz (ML) plots serve as an indicator of heterogeneity and also depict the transmissivity versus the storativity of the payzone. In this work, ML plots are used to study the flow capacity versus the storage capacity of a reservoir, and to divide the reservoir into individual flow units. Production and injection profile logs were used to verify the depths at which CO2 was actually being injected or produced and compared to the depths where a high flow capacity was observed on the ML Plot. Premature production of CO2 and high GOR on producing wells in CO2 floods is attributed to the CO2 being injected and produced in high permeability zones as compared to low or no CO2 injection in low permeability zones. This study proposes a well completion technique using well core data to normalize CO2 injection across various ML defined zones, and thereby improve CO2 conformance and recovery.
High GOR in CO2 flooded reservoirs increases the net and gross utilization of CO2 and may also result in lower vertical sweep efficiency. Controlling the preferential entry of CO2 into high flow capacity regions, and selectively controlling the injection rate into the various flow units of the reservoir can minimize CO2 utilization, increase volumetric sweep efficiency and recovery. This paper presents a simple well completion technique to selectively control CO2 injection into the reservoir for various flow units. The area of flow open to CO2 is controlled by the perforation density. For most practical applications, the perforation density for a flow unit should be inversely proportional to the slope of the flow unit characterized using the ML plots.
Evaluation and Optimization of Enhanced Oil Recovery by WAG Injection at Tapis and Guntong Fields, Malaysia
Authors: Selamat Samsuddin , Samsuddin Seri Ainatrah , Halim Nurazizi Abdul 
Published: July 2011

Abstract
EMEPMI and PETRONAS have recently concluded major simulation studies on the application of immiscible Water Alternating Gas (WAG) injection to enhance oil recovery for Tapis and Guntong fields, the two largest waterflooded fields operated by ExxonMobil in Malaysia. Both fields have been under waterflood operation for more than 25 years with about 40% original-oil-in-place (OOIP) recovered to-date.
Evaluations of immiscible WAG injection process application at Tapis and Guntong fields were carried out using full-field reservoir simulation models. The scope of the evaluation work included: a) assessment of additional recovery from enhancing waterflood operations, b) assessment of recovery uplift from WAG injection, c) WAG pattern and WAG ratio optimization, d) optimal WAG operating parameters and reservoir management strategy, and e) integrating production and injection well operating conditions with facilities process design.
The Tapis WAG evaluation study has supported ExxonMobil's plans to implement a WAG project at Tapis. The study has matured to the point of providing the subsurface design basis for the Project. The Guntong study has provided an initial assessment of WAG potential used for the conceptual WAG development and early project planning.
Residual Oil Saturation Determination for EOR Projects in a Mature West Texas Carbonate Field
Authors: Pathak Prabodh , Fitz Dale E. , Babcock Kenneth P. 
Published: July 2011

Abstract
The technical success of an Enhanced Oil Recovery (EOR) project depends on two main factors - first, the reservoir remaining oil saturation (ROS) after primary and secondary operations, and second, the recovery efficiency of the EOR process in mobilizing the ROS. These two interrelated parameters need to be estimated prior to embarking on a time-consuming and costly process for designing and implementing an EOR process. The oil saturation can vary areally and vertically within the reservoir, and the distribution of the ROS will determine the success of the EOR injectants in mobilizing the remaining oil.
There are many methods for determining the oil saturation (Chang et al. 1988, Pathak et al. 1989) and these include core analysis, well log analysis, Log-Inject-Log (LIL) procedures (Richardson 1973 and Reedy 1984), and Single Well Chemical Tracer Tests (SWCTT). These methods have different depths of investigation and different accuracies, and they all provide valuable information about the distribution of ROS. There is no single method that provides the best estimate of ROS, and a combination of all these methods is essential in developing a holistic picture of oil saturation and in assessing whether the oil in place is large enough to justify the application of an EOR process. As Teletzke et al. (2010) have shown, EOR implementation is a complex process, and a staged, disciplined approach to identifying the key uncertainties and acquiring data for alleviating the uncertainties is essential. The largest uncertainty in some cases is the remaining oil saturation in the reservoir.
This paper presents the results from a field-wide data acquisition program conducted in a West Texas carbonate reservoir to estimate ROS as part of an EOR project assessment. The Means field in West Texas has been producing for more than the past 75 years and the producing mechanisms have included primary recovery, secondary waterflooding and the application of a CO2 EOR process. The Means field is an excellent example of how the productive life and oil recovery can be increased by the application of new technology. The Means story is one of judicious application of appropriate EOR technology to the sustained development of a mature asset. The Means field is currently being evaluated for further expansion of the EOR process and it was imperative to evaluate the oil saturation in the lower, previously-undeveloped zones. This paper briefly outlines the production history, reservoir description and reservoir management of the Means field, but this paper concentrates on the Residual Oil Zone (ROZ) that underlies the Main Producing Zone (MPZ), and describes a recent data acquisition program to evaluate the oil saturation in the ROZ. We discuss three major methods for evaluating the ROS - core analysis, LIL tests and SWCTT tests.