bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanistic Modeling of the Benefit of Combining Polymer with Low Salinity Water for Enhanced Oil Recovery
Authors: Mohammadi Hourshad , Jerauld Gary R. 
Published: April 2012

Abstract
It has long been recognized that there are synergies between EOR (enhanced oil recovery) techniques, as is the case between low salinity waterflooding and polymer flooding. While polymer flooding is a proven technology which improves waterflood recovery efficiency by increasing the water-oil viscosity ratio, low salinity EOR is an emerging technology which enhances the displacement efficiency by changing wettability. One would expect the combined EOR schemes to be at least additive because they target different things. For other reasons, the combination of these two technologies can expand their range of application.
Polyacrylamide polymers widely used in chemical EOR hydrolyze at high temperatures and precipitate if calcium concentration is above 200 ppm. The use of low salinity EOR can make the use of polyacrylamide polymers feasible up to reservoir temperatures of at least 100°C or enable the use of polymers with larger degrees of hydrolysis. Polyacrylamide solution viscosity increases as salinity decreases so OPEX will reduce due to lower required polymer concentration. One third or less of polymer is required with low salinity waterflooding EOR compared to conventional water flooding.
We demonstrate that addition of polymer enhances recovery efficiency and timing of low salinity waterflood. The incremental oil recovery between the homogeneous and heterogeneous cases is close, especially for more viscous oil. At high oil viscosity, combination of low salinity injection water and polymer gives incremental oil recovery about equal or better than the summation of each if used separately. We demonstrate that both secondary and tertiary combined processes are effective but secondary gives better timing. Synergistic behavior of combined processes is more effective in tertiary flood than the secondary cases. Chemical cost comparison of the cases studied shows that a 5-time reduction in chemical cost per barrel of oil recovered can be expected when polymer is added to low salinity. We show that operational constraints in field application can limit the synergy between these combined processes.
A New Dynamic Wettability Alteration Model for Oil-Wet Cores During Surfactant Solution Imbibition
Authors: Kalaei M. Hosein , Green Don W. , Willhite G. Paul 
Published: April 2012

Abstract
Wettability modification of solid rocks by using surfactants is an important process that is used in practical applications such as oil recovery from reservoirs. When wettability is altered, both capillary pressure and phase relative permeability change wherever the porous rock is contacted by surfactant. Due to the complexity of reservoir rock, alteration of the wettability is not uniform throughout the swept area. Although there are several numerical studies in the literature to simulate the effect of wettability alteration on oil recovery from oil-wet rock systems, these wettability alteration models permit alteration of the rock wettability uniformly and independently from time. Properties such as capillary pressure, oil and water relative permeability, and interfacial tension are calculated by the use of an interpolation scaling factor between two wettability extremes: oil-wet and water-wet.
In the present study, a novel time-dependent wettability alteration model is proposed in which the contact angle is correlated to the surfactant concentration through an empirical correlation developed by using experimental data. The model allows the rock wettability to be altered in a heterogeneous manner with time. The proposed model was tested against a number of experimental and simulation results. Very good quantitative agreements between the simulation outcomes and experimental data from the literature were shown. The simulation of surfactant solution imbibition in laboratory scale cores using the proposed new model showed that the wettability alteration should be considered as a dynamic process, which plays a significant role in history matching and prediction of oil recovery from oil-wet porous media. Also, we found that gravity force is the primary cause of surfactant solution getting into the core and changing the rock wettability toward a less oil-wet state.
Application of a Thermally Activated Particle System for Improved Sweep Efficiency in a Multilayer, Geologically Complex Waterflood
Authors: Mustoni J. L. , Cabrera F. A. , Manrique E. J. , Norman C. A. 
Published: April 2012

ABSTRACT
The Cerro Dragon (CD) Field, located in the San Jorge Gulf Basin (SJGB) of Argentina, offers a significant opportunity for improved volumetric sweep efficiency because of an adverse mobility ratio and spatial anisotropy, typical of the multilayered channels deposits of SJGB. The center of these channels becomes a highly conductive "thief zone", resulting in preferential channeling of injected water to the offset producers without creating an oil bank. As a consequence, sweep efficiency is reduced and operating costs are increased due to the handling of large volumes of produced water. These thief zones are the target for improved reservoir conformance using a thermally activated particle technology known as BrightWater® (BW), developed and patented by BP, Chevron and Nalco Company.
Testing of deep reservoir conformance in Argentina utilizing the BW technology began in 2006 with pilots in the Piedra Clavada and Koluel Kaike fields (Mustoni, et al., 2010). Screening, design and implementation of the BW conformance project in the CD Field was the result of experience gained from these earlier applications. The CD Field conformance project represents a larger scale application of the BW technology in terms of number of wells treated, layers per well, oil reserves, and treatment volumes.
This paper describes the methodology utilized to evaluate and rank BW conformance candidates from a database of more than 100 blocks in the CD Field. A detailed discussion of the candidate selection methodology will be presented, including laboratory testing, chemical formulation and volumes, well surveillance, inter-well tracer, and simulation studies.
This paper will also describe details of internally developed processes that optimized the logistics of field implementation, including simultaneous injection of the chemical solution in multiple injection wells and multiple subsurface mandrels.
Study and Field Application of Organic/Inorganic Cross-Linking Blocking Agent for High Temperature Reservoir
Authors: Dai Caili , You Qing , Liu Xuezhe , Wu Wenming , He Long , Zhao Fulin 
Published: April 2012

Abstract
Polymer gel is widely used for conformance control nowadays, but it is not suitable for high temperature reservoir (over 100 celsius degree). In order to solve the above problems, a novel organic/inorganic cross-linking blocking agent is proposed and developed in this paper combined the advantages of organic and inorganic blocking agents. This novel organic/inorganic cross-linking blocking agent is composed of organic resin, silicide and stabilizer. The optimized formula of this agent at 130 celsius degree was screened through gelation performance and thermal stability in the lab. The appropriate mass fraction of organic resin was 4%~7%, the silicide was 1%~5% and the stabilizer was 0.1%~0.3% in the formulas. It is also confirmed that this novel agent is comfortable for in-depth profile control in 100~140 celsius degree reservoir with gelation time of 8~60 h and there is no dehydration phenomenon at 130 celsius degree aging for 3 months. Sand-packed core experiments indicate that this novel agent has good blocking performance, which can further enhance oil recovery. This novel agent had been applied in production well in Oct 2010, by late 2011, the accumulated oil increment is 3081.5 t, the water cut decreased from 98.7% to 80.5% and the input-output ratio is up to 1 : 3.6. The success of field test confirmed that this novel organic/inorganic cross-linking blocking agent is quite suitable for controlling water and has a broad application prospect.
ASP Formulation Design for Heavy Oil
Authors: Zhang Jieyuan , Ravikiran Ravi , Freiberg David , Thomas Charles 
Published: April 2012

ABSTRACT
The objective of the work detailed was to develop an alkaline-surfactant-polymer (ASP) and achieve good oil recovery at low surfactant concentrations. A combination of phase behavior tests, interfacial tension (IFT) measurements (by spinning drop tensiometer) and coreflood tests were used to develop a solution for an oil that had an API gravity of 15 and viscosity of 2,000 cP.
The percentage of heavy oil in world oil production continues to rise as more light oil reservoirs have either depleted or reached their economic limit. However, the recovery factor from heavy oil reservoirs by both primary and secondary production is low, making these reservoirs candidates for chemical EOR technologies.
Phase behavior tests were used as the primary screening method to identify surfactant formulations qualitatively and the promising candidates were validated by IFT measurements (between the surfactant solution and oil) at different salinities to identify the lowest IFT formulation. Static adsorption tests with reservoir core material were used as a further screening step to ensure formulation was a viable option. Finally, linear coreflood tests were performed at reservoir temperature to validate the formulation and optimize chemical concentration. In one coreflood, 80% of waterflood residual oil was recovered using only 0.15% total surfactants and 2,000 ppm polymer.
The success of the ASP coreflood validates the ASP design for this heavy oil. Typically, heavy oil reservoirs may require lower surfactant concentrations due to higher permeability. As a result, such projects could potentially have a higher reward- risk ratio than ASP projects in conventional oil reservoirs.
Importance of a Second Liquid Phase Formation in CO2 Injection into Bitumen Reservoirs and its Effect on Production
Authors: Feizabadi Seyed Ali , Abedi Jalal , Chen Zhangxin 
Published: April 2012

Abstract
The injection of different solvents, such as propane and CO2, into bitumen, has proven to be an effective method in the production of these kinds of reservoirs. However, in some cases, the prediction of large solvent requirements can make it uneconomical. The formation of a second liquid phase has been observed when the solvent is propane or CO2, with the second liquid phase mainly composed of the solvent itself.
The objective of this research is to understand the importance of this second liquid phase and its effect on production. Also, a simulator that can allocate an individual phase to this liquid phase would allow for prediction of the amount of solvent that can be produced and recycled. This makes the cost evaluation of solvent injection processes to be more realistic.
Depending on the reservoir fluid distribution, a three- or four-phase flow can occur in the absence or presence of water. A compositional simulator based on an equation of state is designed to simulate these multiphase situations. This simulator has a four-phase flash and stability subroutine, which make it more realistc compared to other compositional simulators. In fact, it can handle a maximum of three hydrocarbon phases and one aqueous phase. Relative permeability plays an important role in multiphase flow; numerical results indicate that, by increasing the number of phases, there is an increase in project life.
It is valuable to mention that the results of this research can be also used in CO2 sequestration.
Surface Complexation Modeling for Improved Oil Recovery
Authors: Brady Patrick V. , Krumhansl James L. , Mariner Paul E. 
Published: April 2012

Abstract
Coordination chemistry models of oil adhesion to sandstones and calcite allow more precise testing of wettability alteration theories. The primary electrostatic bonds calculated to link oil to most sandstones are oil -NH+ and kaolinite edge &gt;Al-OH2+ sites at pH &lt; 5.5, and oil -COOCa+ and kaolinite edge &gt;Al:Si-O- sites at pH &gt; 5.5; −NH+ and −COOCa+ can also exchange onto basal planes. Low salinity waterfloods should break −NH+ — &gt;AlOH2+ bonds at pH &lt; 5.5 and low salinity, low Ca+2 waterfloods are calculated to eliminate −COOCa+ — &gt;Al:Si-O- bonds at pH &gt; 5.5. Oil is calculated to link electrostatically to calcite through oil − COO- and &gt;CaOH2+ sites, and to a lesser extent through oil −NH+ and calcite &gt;CO3- sites. Sulfate- rich floods are calculated to eliminate &gt;CaOH2+ charge through sulfate sorption. Divalent cation (Ca+2 and Mg+2) – rich floods are calculated to reverse −COO- charge through sorption.
A New Method for Dynamic Calculation of Pattern Allocation Factors in Waterflood Monitoring
Authors: Saadatpoor Ehsan , Karami Hossein , Al-Ajmi Moudi Fahad 
Published: April 2012

Abstract
Successful operation of a waterflood requires the ability to make informed decisions based on pattern voidage replacement ratio (VRR), watercut, and water production rate. These performance measures are calculated from actual performance data using predefined allocation factors. In a pattern, there are several producers, each contributing to the total pattern production. The percentage of total volume produced from each producer is called the allocation factor.
Waterflood performance is commonly monitored and studied using static allocation factors. The monitoring workflow uses the injection and production data from a database, and pattern allocation factors are assigned to production wells as static values based on geometry of waterflood patterns. In fact, the pattern allocation factors are set as a fraction of the area of a circle exposed to that pattern; hence they are constant. The allocation factors will not represent the real physics involved if they are determined based merely on geometry of patterns. Some important parameters, such as water injection rates of patterns, have a major effect on allocation factors. Based on specific assumptions, we have developed equations to define a new allocation factor for production wells.
The dynamic method proposed in this paper includes several parameters that affect patterns—including well radius, distance between wells, and injection rates—and leads to more realistic waterflood monitoring and more efficient decision making with no extra cost or time needed for data gathering or model development and simulation. The effect of using new allocation factors was studied on actual field data, and results verified the possible improvement in performance if dynamic allocation factors are used.
Wettability Survey in Bakken Shale Using Surfactant Formulation Imbibition
Authors: Wang Dongmei , Butler Ray , Zhang Jin , Seright Randy 
Published: April 2012

Abstract
For ultra-tight shale reservoirs, wettability strongly affects fluid flow behavior. However, wettability can be modified by numerous complex interactions and the ambient environment, such as pH, temperature, or surfactant access. In our previous study for Bakken shale imbibition, a group of surfactant formulations were examined—balancing the temperature, pH, salinity, and divalent cation content of aqueous fluids to increase oil production from shale with ultra-low porosity and permeability in the Middle Member of the Bakken Formation in the Williston Basin of North Dakota. To advance this work, this paper determines the wettability of different parts of the Bakken Formation. One goal of this research is to identify if the wettability can be altered using surfactant formulations. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale, and examine the viability of a field application.
Using modified Amott-Harvey tests, the wettability was determined for cores from three wells at different portions of the Bakken Formation. The tests were performed under reservoir conditions (90-120°C, 150-300 g/L formation water salinity) using Bakken crude oil. Both cleaned cores (cleaned by toluene/methanol) and untreated cores (sealed, native state) were investigated. Bakken shale cores were generally oil-wet or intermediate-wet (before introduction to the surfactant formulation). The four surfactant formulations that we tested consistently altered the wetting state of Bakken cores toward water-wet. These surfactants consistently imbibed to displace significantly more oil than brine alone. Four of the surfactant imbibition tests provided EOR values of 6.80% to 10.15% OOIP, incremental over brine imbibition. Ten surfactant imbibition tests provided EOR values of 15.65% to 25.40% OOIP. Thus, imbibition of surfactant formulations appears to have a substantial potential to improve oil recovery from the Bakken Formation. For comparison, recovery factors using the existing production methods are only on the order of a few percent OOIP. Positive results were generally observed with all four surfactants: 17A, 58N, S2, and C1. From our work to date, no definitive correlation is evident in surfactant effectiveness versus (1) temperature, (2) core porosity, (3) whether the core was from the Upper Shale or the Middle Member and (4) whether the core was preserved (sealed) or cleaned prior to use.
Microbial EOR: A Quantitative Prediction of Recovery Factor
Authors: Lacerda Eduarda C. , Priimenko Viatcheslav I. , Pires Adolfo P. 
Published: April 2012

Abstract
Microbial Enhanced Oil Recovery (MEOR) is a promising EOR technique. Feeding bacteria so that they can be stimulated to produce metabolites is a good way to increase recovery factors. In this paper, we present a mathematical model which describes a MEOR process and can be applied to estimate the recovery factor.
A one-dimensional isothermal model, comprising displacement of oil by water containing bacteria and nutrients, is studied. The model is composed by a hyperbolic system of four partial differential equations with source terms and appropriate initial and boundary conditions, solved numerically by a fractional step method. We analyse the case when the produced metabolites are biopolymers which increase water viscosity, and then, improve sweep efficiency.
The required parameters used in this model are not always known, therefore, to better investigate their importance, a sensitivity analysis is run and the impact in the recovery factor observed. The sensitivity analysis was performed according to the following steps:
three values for the maximum specific growth rate were assumed and their impact in the recovery factor is analyzed, to demonstrate the importance of bacteria screening; water viscosity dependence on biopolymer concentration is described by three functions and the resulting recovery factor of each one of them is compared; three different models describing bacteria growth and their effects in the recovery factor are also presented.
Maximum specific growth rate was the parameter that has caused the major impact in the recovery factor. When a small value was adopted, there was no additional oil recovery in comparison to water injection. This sensitivity analysis has shown the importance of laboratory tests to improve the prediction of recovery factor. It was also noticed that a significant incremental oil recovery can be achieved with this process of MEOR for different oil viscosities.
Managing Risk in the Deployment of New Technology - Getting LoSal EOR into the Business
Authors: Reddick C. , Buikema T. , Williams D. 
Published: April 2012

Abstract
This paper documents key learnings from BP's experience in managing the risks associated with deploying LoSal waterflooding technology over the past five years. The paper covers the management of technical risk, operational risk, organisation and resourcing risk, and the risk of failing to secure adequate engagement with decision-makers.
The learnings described in the paper cover experiences gained over multiple projects over different stages of project cycles, including the application of LoSal EOR in onshore and offshore settings, in existing waterflood operations as well as new projects.
On the technical side, the derivation of quality coreflood data, and its calibration with both pilot and single well chemical tracer test data have been key for building confidence in the magnitude and uncertainty of the LoSal response.
Operational risk management has been essential for securing approval for implementation of LoSal EOR. Risks evaluated include loss of injectivity, operability of desalination facilities, and the interface with produced water management. A common learning is the need for building contingency into project design to cover all of these risks.
Organisation and resourcing have required careful consideration, and have been addressed by having a central team conduct LoSal EOR evaluations for multiple assets, in order to make the best use of scarce/critical skills.
Finally, organised and thoughtful engagement with decision-makers has been critical. Securing approval has required a careful and sustained effort, because the concept of LoSal EOR is relatively new, spans multiple disciplines, and often enhances, but does not always enable, new project economics.
Following a careful approach to risk management, LoSal waterflooding has been internally approved for two new offshore projects, key steps in building confidence for the wider application of the technology.