bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Behind-Pipe Saturation in a Miscible CO2 Flood
Authors: Amadi Samuel , Hughes Richard G. 
Published: April 2008

Abstract
To evaluate the amount of bypassed oil in a CO2 flood, it is necessary to obtain some estimate of the remaining oil saturation. Near wellbore oil saturation determination requires a tool or sequence of tools that is able to distinguish oil from other phases that may be present in situ especially when those phases are miscible with the oil.
This paper presents the combined use of several neutron tools to evaluate the remaining oil saturation in a miscible CO2 flood. These techniques are not time lapse techniques and so are applicable even where there are no base cased-hole logs to evaluate.
These methods are applicable in areas where CO2 has been injected for a long period of time without a base pre-CO2 log. The techniques work best with a full suite of open-hole logs to characterize the petrophysical properties of the well and where heterogeneity effects control the displacement process. If petrophysical properties are known or reasonably estimated from other data available, the proposed methods can provide an estimate to the oil saturation that should be adequate to allow go/no go decisions.
Foam Mobility Control for Surfactant EOR
Authors: Li Robert Feng , Yan Wei , Liu Shunhua , Hirasaki George J. , Miller Clarence A. 
Published: April 2008

Abstract
Foam generated in situ by surfactant alternated with gas injection is demonstrated as a substitute for polymer drive in the alkaline-surfactant-polymer (ASP) EOR process. Foam is also effective in a similar process for a 266 cp crude oil, even though the system did not have enough polymer for favorable mobility control. Foam is shown to greatly enhance sweep efficiency in a layered sandpack with a 19:1 permeability ratio. Foam diverted surfactant solution from the high-permeability layer to the low-permeability layer. Ahead of the foam front, liquid in the low-permeability layer crossflowed into the high-permeability layer. A layered system with a 19:1 permeability contrast could be completely swept in 1.3 TPV (total pore volume) with foam while waterflooding required 8 PV (pore volume).
Air Foam Injection for IOR: from Laboratory to Field Implementation in ZhongYuan Oilfield China
Authors: Yu Hongmin , Yang Baoquan , Xu Guorui , Wang Jiexiang , Ren Shao Ran , Lin Weimin , Xiao Liang , Gao Haitao 
Published: April 2008

Abstract
The Hu-12 Block, located in ZhongYuan Oilfield, Henan Province China, contains many small but highly heterogeneous oil reservoirs, with low permeability oil bearing formations and high permeability mixed (oil/water) layers. The reservoir temperature is 90 °C, and the original reservoir pressure of nearly 25 MPa, and with high salinity of formation water (around 200,000 mg/l). After 20 years of water injection, the recovery factor achieved was only 20–25%, and average water cut has reached to over 95%. N2 gas injection has been tried with less success due to early gas breakthrough from high permeability zones. Since 2006, high pressure air foam and air injection (Air Foam Alternative Air Injection, AFAAI) has been proposed and implemented in one of the reservoirs, in order to block high permeability water zones and increase the sweeping efficiency of air and water injection. A series of laboratory experiments have been conducted to study the oxidation kinetics of air/air foam with oil and the blocking and displacement efficiency of air foams in different oil sands. Reservoir simulation has also been carried out for predicting the reservoir response to air foam injection and optimizing the injection process. Air foam and air injection was started in the field since May 2007 in a well group with 1 injector and 4 producers, using a small high pressure air compressor (40 MPa, 7 m3/min air rate). Up to now, 460,000 Nm3 air and 2920 m3 foam surfactant solution have been injected into the reservoir. The field results show that no oxygen/N2 breakthrough was observed and a significant increase in oil production with water cut reduced by 4%. The detailed laboratory study and field experience are presented in this paper.
The Modeling Challenge of High Pressure Air Injection
Authors: de Zwart A. H. , van Batenburg D. W. , Blom C. P. A. , Tsolakidis A. , Glandt C. A. , Boerrigter P. 
Published: April 2008

AbstractHigh Pressure Air Injection (HPAI) is a potentially attractive enhanced oil recovery method for deep, high-pressure light oil reservoirs after waterflooding. The advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas, is its availability at any location. HPAI has been successfully applied in the Williston Basin for more than twenty years and is currently being considered by many operators for application in their assets.Evaluation of the applicability of HPAI requires conducting laboratory experiments under reservoir temperature and pressure conditions to confirm crude auto-ignition and to assess the burn characteristics of the crude/reservoir rock system. The ensuing estimation of the potential incremental recovery from the application of HPAI in the reservoir under consideration requires fit-for-purpose numerical modeling. Typically, the flue gas generated in-situ by combustion leads to in an immiscible gas drive, where the stripping of volatile components is a key recovery mechanism. HPAI has therefore, in some instances, been modeled as an isothermal flue gas drive, employing an Equation of State (EOS) methodology. This approach, however, neglects combustion and its effects on both displacement and sweep. Furthermore, the EOS approach cannot predict if, and when, oxygen breakthrough at producers occurs. Combustion can be included in a limited fashion in simulations at the expense of extra computational time and complexity. In the available literature, combustion is taken generally into account under quite simplified conditions.This paper addresses the role that combustion plays on the incremental recovery of HPAI. Numerical simulations were conducted in a 3D model with real geological features. In order to capture more realistically the physics of the combustion front, a reservoir simulator with dynamic gridding capabilities was used. Kinetic parameters were based on the combustion tube laboratory experiments. The impact of combustion on residual oil, sweep efficiency and predicted project lifetime is presented by comparing isothermal EOS-simulations and multi-component combustion runs.
Insurance Value of Intelligent Well Technology against Reservoir Uncertainty
Authors: Addiego-Guevara E. A. , Jackson M. D. , Giddins M. A. 
Published: April 2008

Abstract
Significant challenges remain in the development of optimized control techniques for intelligent wells, particularly with respect to properly incorporating the impact of reservoir uncertainty. Most optimization methods are model-based and are effective only if the model can be used to predict future reservoir behavior with no uncertainty. Recently developed schemes, which update models with data acquired during the optimization process, are computationally very expensive.
We suggest that simple reactive control techniques, triggered by permanently installed downhole sensors, can enhance production and mitigate reservoir uncertainty across a range of production scenarios. We assess the implementation of an intelligent horizontal well in a thin oil rim reservoir in the presence of reservoir uncertainty, and evaluate the benefit of using two completions in conjunction with surface and downhole monitoring. Three control strategies are tested. The first is a simple, passive approach using a fixed control device to balance inflow along the well, sized prior to installation. The second and third control strategies are reactive, employing intelligent completions that can be controlled from the surface. The second strategy opens or closes the completions according to well water cut and flow rate and individual downhole rate and phase measurements obtained from a surface multiphase flowmeter and alternating zonal well tests. The third strategy proportionally chokes the completions as increased completion water cut is measured using downhole multiphase flowmeters.
A cost-benefit analysis demonstrates that reactive control strategies always yield a neutral or positive return, whereas a passive, model-based strategy can yield negative returns if the reservoir behavior is poorly understood. While reactive control strategies enhance production and mitigate reservoir uncertainty, they may not deliver the optimum possible solution. Proactive control techniques, which additionally incorporate data from downhole reservoir-imaging sensors, may yield near- optimal gains.
Kuparuk MWAG Project after 20 Years
Authors: Shi Wen , Corwith Jeff , Bouchard Andre , Bone Russ , Reinbold Eric 
Published: April 2008

Abstract
Through many phases of expansion, the Kuparuk hydrocarbon miscible water-alternating-gas (MWAG) project has grown from 10 patterns on 2 drillsites (Small Scale EOR, or SSEOR) to today&s 283 patterns on 32 drillsites. It now covers an area with almost 4 billion barrels of STOOIP and has generated an estimated 120 MMSTB of incremental oil sales.
The original goals of the MWAG project were twofold: First, there being no available market for produced gas, to efficiently store associated gas in the reservoir (avoiding the rapid recycling of gas observed with other processes); and second, to generate incremental tertiary oil production. The project is approaching its target maturity, especially in the C sand. But the lower throughput A sand has some immature patterns showing lower-than-expected tertiary oil response. Despite the relative maturity of the MWAG flood, expansion opportunities still exist. Based on fine grid compositional simulation, an expansion of MWAG to drillsite "A" is under evaluation.
This paper provides a brief review of the Kuparuk MWAG project&s history, an overview of current status and flood management practices, and describes the latest investigation into further expansions.
ASP Processes: Wide Range of Conditions for Good Recovery
Authors: Liu Shunhua , Li Robert Feng , Miller Clarence A. , Hirasaki George J. 
Published: April 2008

Abstract
Design of an alkaline-surfactant-polymer (ASP) process requires knowledge of the amount of soap formed under alkaline conditions from naphthenic acids in the crude oil. We show here for several crude oils that the acid number determined by nonaqueous phase titration is approximately twice that found by hyamine titration of a highly alkaline aqueous phase used to extract soaps from the crude oil. This acid number by soap extraction should provide a better estimate than nonaqueous phase titration. This soap interacts with the injected surfactant to form surfactant films and microemulsion droplets during an ASP process.
In a previous paper (Liu et al., 2006), an unusually wide range of salinities of ultra-low oil-water interfacial tensions (IFTs) was found for one alcohol-free crude oil/anionic surfactant system under alkaline conditions where naphthenic soaps were present. This surprising and favorable behavior has now been found to exist with the same surfactant blend and another crude oil.
In the same paper, a one-dimensional simulator for the ASP process was presented. Here this ASP simulator has been used for various acid contents, injected surfactant concentrations, slug sizes and salinities to show that high recoveries of waterflood residual oil (&gt;90%) can be expected for a wide range of near-optimal (Winsor III) and under-optimum (Winsor I) conditions for a constant salinity process, even with relatively small slug sizes. A key factor leading to this good performance is development of a gradient in soap-to-surfactant ratio, which assures that a displacement front with ultralow IFT forms and propagates through the formation. Similar high recoveries can be attained for certain over-optimum (Winsor II) conditions but only for much larger slug sizes owing to the tendency for surfactant to partition into the oil phase and become retarded. Large dispersion such as might be expected for field conditions can significantly reduce recovery for small surfactant slugs even for near- optimal and under-optimum conditions. However, this problem can be overcome by injecting the slug and/or drive at salinities below reservoir salinity, thereby creating a salinity gradient.
Time-Dependent Injectivity During CO2 Storage in Aquifers
Authors: Burton McMillan , Kumar Navanit , Bryant Steven L. 
Published: April 2008

Abstract
Economic considerations are likely to drive operators of geologic storage projects to inject as much CO2 as possible into the smallest number of wells. In practice, then, a CO2 injection well is likely to run at the largest bottomhole pressure that is safe. However, a constant-pressure well exhibits a varying rate of CO2 injection because of classical multiphase flow effects, and also because long-term injection of CO2 dries out the near-wellbore region. Drying removes water but precipitates dissolved salts, so the permeability of the dry rock need not equal the initial aquifer permeability. In addition to mobility of CO2 in the dried rock, the injectivity depends strongly on the mobility of the two-phase flow region. The difference in injectivity for seven different measured CO2-brine relative permeability curves is substantial. Characterizing relative permeability will therefore be an important consideration for the practical implementation of CO2 storage projects. The analytical expressions developed here show that injectivity variation can be understood in terms of phase mobilities and the speeds of saturations fronts. The expressions can refine the estimate of the number of wells needed for a target overall injection rate. Well count in turn strongly affects the economics of sequestration projects.
Impact of Phase Behavior Modeling on In-Situ Combustion Process Performance
Authors: Kristensen M. R. , Gerritsen M. G. , Thomsen P. G. , Michelsen M. L. , Stenby E. H. 
Published: April 2008

Abstract
To facilitate the study of reactive-compositional porous media processes we develop a virtual kinetic cell (single-cell model) as well as a virtual combustion tube (one-dimensional model). Both models are fully compositional based on an equation of state. In this work, we apply the models to analyze phase behavior sensitivity for in-situ combustion, a thermal oil recovery process.
For the one-dimensional model we first conduct sensitivity analyses to numerical discretization errors and provide grid density guidelines for proper resolution of in-situ combustion behavior. A critical condition for success of in-situ combustion processes is the formation and sustained propagation of a high-temperature combustion front. Using the models developed we study the impact of phase behavior on ignition/extinction dynamics as a function of the operating conditions. We show that when operating close to ignition/extinction branches, a change of phase behavior model is likely to shift the system from a state of ignition to a state of extinction or vice versa. For both the rigorous equation of state based and a simplified, but commonly used, K-value based phase behavior description we identify areas of operating conditions which lead to ignition. For a particular oil we show that the simplified approach overestimates the required air injection rate for sustained front propagation by 17% compared to the equation of state based approach.
Using Co-Solvents to Provide Gradients and Improve Oil Recovery during Chemical Flooding in a Light Oil Reservoir
Authors: Dwarakanath V. , Chaturvedi T. , Jackson A. C. , Malik T. , Siregar A. , Zhao P. 
Published: April 2008

Abstract
The effect of co-solvent on phase behavior was evaluated and an optimal surfactant/co-solvent formulation was selected based upon a combination of simulations and laboratory experiments. The co-solvent altered phase behavior, thereby necessitating a different approach for inducing effective salinity gradients. We present an approach where the hydrophilic nature of the co-solvent is used to maintain effective salinity gradients to optimize surfactant behavior but more importantly mitigate viscous microemulsions and reduce surfactant retention. By using a combination of laboratory experiments and simulations to match co-solvent behavior in UTCHEM, Using an understanding into co-solvent partitioning was developed such that the optimal conditions of ultra-low interfacial tensions are maintained for a longer duration during chemical flooding. We demonstrated that by adding the appropriate co-solvent and the correct amount of electrolyte in the chase solutions, we could maintain Winsor type III conditions for extended durations even with a small surfactant slug. The optimal co-solvent/electrolyte gradient recovered more than 90% of the residual oil in laboratory corefloods. The result illustrate the importance of characterizing the effect of co-solvent on surfactant phase behavior and the need for numerical modeling to optimize chemical flood design when co-solvent is used.
The Potential for Additional Carbon Dioxide Flooding Projects in the United States
Authors: Mohan Hitesh , Carolus Marshall , Biglarbigi Khosrow 
Published: April 2008

Abstract
In recent years, sustained increases in crude oil prices and continued decline in domestic conventional production have renewed national interest in Carbon Dioxide Enhanced Oil Recovery (CO2 EOR). Growing concern about climate change and greenhouse gases has increased interest in carbon capture and sequestration. CO2 EOR provides a value added opportunity to increase crude oil production and sequester substantial volumes of industrial CO2.
An analysis was conducted to determine the incremental domestic production which could be realized if industrially produced CO2 is made available for EOR. The challenges are the volumes of CO2 which can be made available, the infrastructure requirements, and the prices at which the CO2 can be made available. 1,673 potential CO2 EOR candidate reservoirs (with an estimated technical recovery of about 20 Billion barrels) were analyzed. These reservoirs were timed and developed subject to the availability of CO2 at a price economical to the EOR producer. To determine CO2 availability, a wide array of natural and industrial CO2 sources was mapped along with candidate EOR reservoirs. Potential pipeline routes were developed to determine the volume of CO2 available from each industrial source, and to calculate the tariff required to transport it to potential fields. Where volumes from concentrated sources like ethanol or hydrogen plants were insufficient for a project, several such sources were linked through gathering lines and connected to potential fields through a trunk line. The price of industrial CO2 delivered to the producer includes the capture cost and regional pipeline tariff. This price was used to determine the economics and development of EOR projects.
The analysis indicates that by increasing availability of CO2 through wide-spread capture and sale of CO2 from industrial sources, and with oil prices between $45–$60/Bbl, approximately 1.2 Million barrels per day (MMBbl/d) of incremental oil production can be realized while sequestering ∼300 Million tons per day (Mtn/d) of CO2.
LoSal™ Enhanced Oil Recovery: Evidence of Enhanced Oil Recovery at the Reservoir Scale
Authors: Lager A. , Webb K. J. , Collins I. R. , Richmond D. M. 
Published: April 2008

Abstract
For over 10 years research has been carried out on the impact of low salinity waterflooding on oil recovery. Data derived from corefloods, single well tests, and log-inject-log tests have shown that injecting low salinity water into an oil reservoir should result in a substantial increase in oil recovery in many cases. The results varied from 2 to 40% increases in waterflood efficiency depending upon the reservoir and composition of the brine.
In 2005, a hydraulic unit was converted to inject low salinity brine into an Alaskan reservoir, by switching a single injection pad to low salinity water from high salinity produced water. An injector well and 2 close production wells were selected within a reasonably well constrained area. A surveillance programme was devised which included capturing produced water samples at regular intervals for ion analysis and the capturing of production data.
Detailed analysis of the production data, and the chemical composition of the produced water, demonstrated an increase in oil production and provided direct field evidence of the effectiveness of LoSal™ at inter-well scales. Additionally, the response of the reservoir to low salinity water injection was confirmed by single well chemical tracer test.
In parallel, laboratory studies have led to mechanistic understanding of LoSal™ in terms of multiple-component ionic exchange (MIE) between adsorbed crude oil components, cations in the insitu brine and clay mineral surfaces. The results clearly show that the enhanced oil production and associated water chemistry response was consistent with the MIE mechanism proposed.
The oil production data have been modeled using an in-house developed modification to Landmark's VIP™ reservoir simulation package. An excellent match for the timing of the oil response was obtained which provides a good basis for predicting the result for large scale application of LoSal™ flooding.
Effective Use of Heterogeneity Measures in the Evaluation of a Mature CO2 Flood
Authors: Senocak Didem , Pennell Stephen P. , Gibson Charles E. , Hughes Richard G. 
Published: April 2008

Abstract
Heterogeneity measures have a long history in the oil and gas industry but have fallen somewhat out of favor in recent years with the advent of more statistically robust characterization tools. Theoretically-based correlations between heterogeneity measures and recoveries at various stages of a waterflood appear to be one of the primary tools in the design and early evaluation of floods when they were initially proposed. Field-wide reports of the heterogeneity measures and their relationship to enhanced recovery response were also reported in the literature, but it is unclear as to whether general correlations were developed or widely used as they were for waterflooding.
In this work we evaluate several heterogeneity measures in terms of recovery efficiency and utilization rate in a mature CO2 flood. Core studies available from 41% of the wells in the Little Creek Field, Mississippi were used to compute various heterogeneity measures and the resulting values were correlated with pattern-by-pattern and development area recoveries and CO2 utilization rates at various times over the life of the flood. Weak correlation trends were found for most of the measures when recoveries were evaluated. Slightly stronger correlations were found with utilization rates.
Much more significantly, mapping of the well-by-well heterogeneity measures appear to show geological trends better than traditional maps of the basic parameters that make up the measures. These geological trends were then successfully used to adjust rock-types and guide geostatistical modeling of permeability and porosity when performing reservoir modeling and history matching.