bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Including Tracer Data in the EnKF Approach
Authors: Valestrand Randi , Sagen Jan , Nævdal Geir , Huseby Olaf , Forghany Saeed 
Published: April 2008

Abstract
This paper presents for the first time: Coupling of the EnKF methodology and tracer data, a new developed tracer simulator which accounts for partitioning gas tracers, and coupling of the EnKF methodology with partitioning gas tracer data.
The ensemble Kalman Filter (EnKF) has recently gained popularity as a method for history matching. The EnKF includes online update of parameters and the dynamical states. An ensemble of model representations is used to represent the model uncertainty.
Tracers are widely used to increase the understanding of fluid flow. Tracers can be used to label injection fluids, hence, well connections and fluid patterns can be established when the tracer appears in production wells. Tracer data contains valuable information but are typically underexploited; most of the tracer-tests are only evaluated in a qualitative manner, without any kind of comparison to simulation results.
This paper brings together tracer and modelling competence by including tracer data as measurements in the EnKF methodology.
Gas tracers in reservoirs are partitioning tracers and must be modelled as such. This requires that adequate options are available for modelling of these tracers, both with respect to convection terms and diffusion/dispersion terms in the conservation equation. In this paper we therefore present a new tracer simulator, which includes partitioning of gas tracers. The tracer simulator includes separate time step control and a second order spatial numerical scheme to reduce numerical smearing of the tracer data, and has been coupled with the EnKF methodology.
The value of tracer data, and partitioned tracer data, in the EnKF approach is demonstrated on North Sea based examples. The permeability and fault transmissibility multipliers of the reservoirs are estimated by EnKF. These examples show that tracer data can be used successfully in an automatic updating scheme, not only by the traditionally manual updating.
Mechanisms of Enhanced Natural Imbibition with Novel Chemicals
Authors: Zhang Jieyuan , Nguyen Quoc P. , Flaaten Adam K. , Pope Gary A. 
Published: April 2008

Abstract
A large body of literature has reflected an extensive experimental study of natural imbibition driven by local capillary pressures at high interfacial tension. However, water imbibition induced by emulsification at low interfacial tension is not well understood. Recently, anionic surfactants have been shown to induce imbibition in mixed wet and oil wet carbonates. Sodium carbonate has been used to reduce the surfactant adsorption. However, calcium and other divalent cations can cause precipitation of the alkali unless soft water is used. This is a significant limitation of sodium carbonate. The present research both advances our understanding of the use of chemicals to enhance oil recovery from fractured carbonate reservoirs and indicates how the process can be optimized using novel chemicals. This research applies to the improvement of oil recovery from mixed wet and oil wet fractured carbonate reservoirs.
We show how to select and evaluate new chemicals as natural imbibition enhancers in carbonate rocks. A novel experimental method has also been developed to quantify the significance of capillary and emulsification driven imbibition due to the presence of the chemical imbibition enhancers. An in situ imbibition profile was visualized using a CT X-ray scanning technique. The results show that formation of microemulsion strongly promotes water imbibition. The rate was highest for Winsor Type II microemulsion and lowest for Winsor Type I microemulsion. The alkalis exhibited a striking imbibition enhancement driven mainly by alteration of capillary pressure. The performance of the imbibition enhancers was found to be consistent for different core plug sizes and boundary conditions. A novel alkali has been tested that shows a high tolerance for hardness and thus may be a good alternative to sodium carbonate under some conditions.
The application of low-cost chemicals to enhanced oil recovery from fractured carbonates is an extremely significant development due to the vast volumes of oil in such reservoirs and the lack of practical alternative methods of recovering such oil.
A New Polymer Application for North Sea Reservoirs
Authors: Spildo K. , Skauge A. , Aarra M. G. , Tweheyo M. T. 
Published: April 2008

Abstract
Field trials have demonstrated increased oil recovery by injection of colloidal dispersion gels (CDG). Characteristics of these trials include reservoirs characterized by high permeability heterogeneity and low injection water salinities. The enhanced oil recovery (EOR) has been attributed to improved waterflood sweep in the rather heterogeneous reservoirs where this method has been applied. The present study presents an investigation of the applicability of colloidal dispersion gels at higher salinity, and in particular directed at North Sea oil reservoir applications.
Earlier laboratory work and field trials involving CDG have involved rather low reservoir temperatures and low injection water salinity (~ 5000 μg/g). This study involves experiments at high temperature (85 0C) and salinity (~35 000 μg/g). When cross-linking is complete the CDG solutions have slightly lower viscosities than the corresponding polymer solutions, and they also appear to be more stable at high temperatures.
In preparation for a field pilot, several core flood experiments have been made. Significant increase in oil recovery due to CDG injection has increased the interest for a field trial in a North Sea oil field. On average, 40 percent of the remaining oil after waterflooding was produced by CDG injection in linear core floods, and a mechanism of microscopic diversion is proposed to explain these results. Our hypothesis is that CDG can contribute as an EOR method giving both a microscopic diversion and a macroscopic sweep.
Heavy-Oil Recovery by Steam Injection in Fractured Reservoirs
Authors: van Heel A. P. G. , van Dorp J. J. , Boerrigter P. M. , Rijswijk B. V. 
Published: April 2008

Abstract
Using analytical results and thermal reservoir simulations, we study the heating of - and oil recovery from - a vertical stack of matrix blocks. The stack is surrounded by fractures, where steam is injected at the top and oil recovered from the base of the fracture system.
We compare fine-grid single-porosity simulations with coarse-grid dual-permeability simulations (where the matrix-fracture interaction is modelled via shape-factors). We independently validate the simulation results with new analytical results for the recoveries due to thermal expansion and temperature-induced viscosity reduction.
Our dual-permeability results show that the early-time heating of the matrix cannot be captured using a constant shape-factor. We analytically derive the time-dependent (transient) shape-factor that captures the heating of the blocks for all time-scales.
When this transient shape-factor is used in combination with an analytically derived viscosity correction (to capture the effect of the temperature profile inside a matrix-block), the coarse-grid dual-permeability simulations accurately reproduce the finegrid single-porosity simulations and analytical results
Mechanistic Models of Microbe Growth in Heterogeneous Porous Media
Authors: Khan Hasnain A. , Gbosi Akpobari , Britton Larry N. , Bryant Steven L. 
Published: April 2008

Abstract
Stimulating growth of indigenous microbes is a low cost method for improving sweep efficiency in water flooded reservoirs. Because injected nutrients for bacterial growth and biofilm development automatically enter thief zones, permeability reduction by accumulated biomass can channel the subsequently injected water into low permeability areas and thus increase sweep efficiency and the recovery factors.
We previously reported biofilm growth that preferentially reduced permeability of a high-permeability layer within a laboratory column. Here we show that traditional models of microbial behaviour in batch experiments do not explain the behaviour of the same microbes in flow experiments. Moreover, a standard model of the microbe behaviour during flow in a homogeneous porous medium cannot predict the behaviour in a heterogeneous medium. We discuss the present situation in understanding the growth of bacteria, nutrient consumption trends and their modeling in batch experiments. This paper also presents the possibility that quorum sensing is involved in the heterogeneous bead packs. We consider the capabilities of two simulators of coupled flow and reactive transport to account for experimental observations.
Applications of MEOR techniques require accurate modeling of experiments before field application. This paper analyzes previous mechanistic models and experiments and outlines a modeling approach based on architecture and behaviour of biofilms. Such a model would account for the changing trend of nutrient consumption by bacteria with the increasing biomass and the onset of biofilm formation.
Experiments to Investigate Steam Injection in Light Oil Fractured Carbonates
Authors: Verlaan Marco , Boerrigter Paul , Oedai Sjaam , van Dorp Johan 
Published: April 2008

Abstract
Conventional displacement methods such as water flooding do not work effectively in densely fractured reservoirs. In such reservoirs one has to rely on recovery mechanisms like capillary imbibition or gravity to recover oil from the reservoir rock matrix. In oil-wet or mixed-wet fractured carbonates only gravity drainage remains a feasible process. However, low permeabilities result in low gravity drainage production rates with high remaining oil saturation.
EOR methods have the potential to improve GOGD drainage rate and ultimate recovery. Especially for shallow fractured reservoirs, it may be attractive to inject steam to improve oil rate and recovery. Heating of the matrix will result in oil expansion, reduction of viscosity, solution gas drive and steam stripping of intermediate hydrocarbon components. Solution gas drive and steam stripping effects potentially become more important than the viscosity reduction.
We experimentally investigated the physical mechanisms involved. We present the results of a laboratory study in which reservoir core with light crude oil at reservoir conditions is heated to steam temperature. From these experiments and separate PVT measurements the effects of thermal expansion of oil, gas liberation and initial water saturation are investigated. The experiments are interpreted numerically by detailed modelling of the observed production. The results show that connate water has a big impact on the gas drive and distillation process, and as a consequence enhances the oil recovery.
Enhanced Gas Recovery and CO2 Sequestration by Injection of Exhaust Gases from Combustion of Bitumen
Authors: Sim Steve S. K. , Brunelle Patrick , Turta Alex T. , Singhal Ashok K. 
Published: April 2008

Abstract
Enhanced gas recovery by gas-gas displacement can be achieved economically in several situations. For mature volumetric gas reservoirs suffering from low productivity due to low reservoir pressure, injection of waste gas can increase the ultimate gas recovery by maintaining gas production rates and preventing premature well abandonment. For water-driven gas reservoirs, pressure maintenance by gas injection will serve to (1) retard the influx of aquifer and (2) partially mitigate water coning caused by excessive pressure drawdown.
This paper presents the results of laboratory core displacement tests conducted to investigate the feasibility of enhanced natural gas production by using exhaust gas from combustion of bitumen in an oxygen rich atmosphere. A synthetic gas mixture containing carbon dioxide, nitrogen and sulfur dioxide was used to represent the exhaust gas of interest. Displacement tests were conducted in Berea core and in porous media prepared with silica sand as well as crushed carbonate rocks at pressures ranging from 0.69 to 6.2 MPa. The objectives of the experiments were to determine the effects of (1) pressure, (2) displacing gas composition (3) formation water and (4) rock mineralogy on recovery efficiency of uncontaminated methane from the porous media.
Several interesting phenomena were observed during the course of this investigation. Separation of injection gas components was observed in the effluent gas during displacement. Breakthrough of carbon dioxide and sulfur dioxide were delayed relative to nitrogen. This can be attributed to the higher solubility of CO2 and SO2 in water relative to nitrogen. These results are beneficial to natural gas production as they reduce the operating costs associated with corrosion during production of CO2 and SO2. The amount of green house gases and acid gases being sequestered in the reservoir will also increase due to these effects.
A Systematic Laboratory Approach to Low-Cost, High-Performance Chemical Flooding
Authors: Flaaten Adam K. , Nguyen Quoc P. , Pope Gary A. , Zhang Jieyuan 
Published: April 2008

Abstract
We present a systematic study of laboratory tests of alternative chemical formulations for a chemical flood design and application. Aqueous and microemulsion phase behavior tests have previously been shown to be a rapid, inexpensive and highly effective means to select the best chemicals and minimize the need for relatively expensive core flood tests. Microemulsion phase behavior testing was therefore conducted using various combinations of surfactants, co-solvents and alkalis with a particular crude oil and reservoir conditions of interest. Branched alcohol propoxy sulfates and internal olefin sulfonates showed high performance in these tests, even when mixed with both conventional and novel alkali agents. Systematic screening methods helped tailor and fine-tune chemical mixtures to perform well under the given design constraints. The best chemical formulations were validated in core flood experiments, and compared in terms of both oil recovery and surfactant retention in cores. Each of the four best formulations tested in core floods gave nearly 100% oil recovery and very low surfactant adsorption. The two formulations with conventional and novel alkali agents gave almost zero surfactant retention. In standard practice, soft water must be used with alkali, but we show how ASP flooding can be used in this case even with very hard, saline brine.
Range of Operability of Gas-Assisted Gravity Drainage Process
Authors: Mahmoud T. N. , Rao D. N. 
Published: April 2008

Abstract
The gas-assisted gravity drainage (GAGD) process is being developed to overcome the limitations of, and as an alternative to, the conventional WAG process. In our recent paper (SPE 110132) we have presented the visual model results to demonstrate the feasibility of the GAGD process and the various mechanisms responsible for the high recoveries achieved. In this paper, we present visual and quantitative results from the physical model experiments to demonstrate the various modes of operability of GAGD, its applicability to fractured reservoirs, the effect of oil viscosity and a comparison of its performance with WAG and CGI processes.
A Hele-Shaw type model - consisting of two parallel glass plates (23" × 13" × in size) with gap between them filled with Ottawa silica sand - has been used in all experiments with a perforated plastic tube serving as the horizontal production well placed at the bottom of the model. Vertical tubes were placed at different depths in the model to serve as gas injectors. The presence of fractures was simulated by placing cylindrical shaped fine wire mesh tubes into the sandpack. Separate models were built to study the effect of gas injection rate, depth, CGI, WAG, huff-and-puff, toe-to-heel, oil viscosity and wettability.
This paper presents video images of the GAGD process in operation in various modes and discusses the quantitative results of these experiments that led us to conclude that, with the exception of toe-to-heel operation, the GAGD process yielded positive results in all the tests with oil recoveries ranging from 54% to 83% OOIP.
This study demonstrates improved GAGD oil recoveries over CGI and WAG, in fractured model over homogeneous, in oil-wet media over water-wet, thereby signifying the potential for wide applicability of the process in both secondary and tertiary modes.
Improving Wateflood Recovery: LoSal™ EOR Field Evaluation
Authors: Seccombe James C. , Lager Arnaud , Webb Kevin , Jerauld Gary , Fueg Esther 
Published: April 2008

Abstract
This paper reviews the effect of brine composition on LoSal™ EOR waterflood recovery. An improved understanding of the LoSal™ mechanism is presented. Corefloods and single-well tracer tests were performed to evaluate the mechanism and quantify recovery benefits. It was determined that recovery is a function of water chemistry and formation mineralogy. Project economics are significantly enhanced by injecting a slug of low salinity water versus continuous injection. It was determined that a 40% slug by pore volume is fully effective.
The work presented in this paper was done to quantify tertiary LoSal™ EOR benefits at the Endicott field located on the North Slope of Alaska. An interwell test is currently underway to unambiguously measure LoSal™ EOR response at field scale.
Simulation Evaluation of Gravity Stable CO2 Flooding in the Muddy Reservoir at Grieve Field, Wyoming
Authors: Wo S. , Yin P. , Blakeney-DeJarnett B. , Mullen C. E. 
Published: April 2008

Abstract
Grieve oil field, discovered in 1954, is located in southeastern Wind River Basin, central Wyoming. This Lower Cretaceous, valley-fill and channelized, Muddy sandstone reservoir is a stratigraphic/structural trap with an average structural dip of 15 degrees. Multiple recovery mechanisms have contributed to produce more than 30 million barrels of premium light sweet crude, including gas expansion, down-dip water drive, and re-injection of produced gas into the field's gas cap. The reservoir depth, at 6,900 ft, and oil gravity, 37°API, are considered favorable for miscible gravity stable CO2 flooding to enhance oil recovery.
Three distinct reservoir lithofacies are identified within the Muddy channel sand at Grieve Field, which are overlain by a low-permeability sandstone interval of bay-head delta deposition. Wettability tests indicate that the reservoir rock is weakly water-wet. A full-field simulation model was developed to simulate the production history and forecast the performance of various CO2 flooding scenarios.
The simulation evaluation concluded that gravity stable CO2 flooding can be an effective EOR method for the Grieve Muddy reservoir. Up to 23 MMSTBO could ultimately be recovered by gravity stable CO2 flooding. To repressurize the reservoir to an operation pressure above the minimum miscibility pressure, a cumulative injection of 90 BSCF or more of CO2 would be needed before any production. Total CO2 purchased is estimated to be in the 119 to 188 BSCF range depending on the operation duration and CO2 injection rate. The net CO2 usage efficiency, the ratio between total purchased CO2 and total produced oil, varies from 7.3 to 8.1 MSCF/BO in the simulated cases. The reservoir has potential to sequester more than 145 BSCF of CO2 at the end of CO2 flooding operation.
A Globally-Convergent Flash Calculation for Constant K-Values Based on a Parameterization of the Tie-Line Field
Authors: Juanes R. 
Published: April 2008

Abstract
We propose a novel approach to flash calculation, with particular application to negative flash. The ability to compute a negative flash for any composition state is important in practice, as the construction of analytical solutions for multicomponent systems by the method of characteristics (MOC) relies heavily on the identification of tie lines and tie-line extensions. MOC solutions are at the heart of some techniques for the calculation of the minimum miscibility pressure, and are the key building blocks for fast simulation of multidimensional reservoir flows by the front-tracking / streamline method.
The basis of the proposed negative-flash method is a parameterization of the tie-line field. Rather than solving the Rachford Rice equation (or any of its variants) we solve directly for the parameters defining the tie line. For an N-component system, our approach leads to a system of N − 2 quadratic equations, which we solve efficiently using a Newton method. The iterative method is very robust: unlike other negative flash procedures, the solution displays continuous dependence on the overall composition, even in the transition to negative concentrations. We illustrate the properties and behavior of the proposed approach on three-component and four-component systems, and we then generalize the method to systems of N components. From the global triangular structure of the system with constant K-values, it follows that the system of N − 2 quadratic equations can only have two roots. For the important case of three components, the flash calculation is explicit.
New Generation Silicate Gel System for Casing Repairs and Water Shutoff
Authors: Burns Lyle D. , Burns Michael , Wilhite Paul , McCool Stan , Oglesby Ken , Glass Jim 
Published: April 2008

Abstract
The SPI gel system is a low cost, multi-component silicate based gel, mixed at surface and pumped as a single stage with controlled gel times ranging from a few hours to several days to form a variety of resilient gels from hard, "ringing" to soft, weak gels. This new environmentally friendly, "green" gel system uses low chemical concentrations and no heavy metals for a low overall cost. SPI gel systems were developed to solve water conformance problems on injector and producer wells, for casing leak repairs and other applications.
The SPI pre-gelled system has a low viscosity for deep penetration of leaks and tight formations and it can be designed for special applications. Well over 1000 lab tests were performed to evaluate the SPI gel system at the RTA Systems laboratory. Further rheological testing was conducted and is in progress at the Tertiary Oil Recovery Project at the University of Kansas. Lab tests are continuing to establish a minimum 5-year life of the SPI silicate gels for permitted injection well repairs for regulatory Mechanical Integrity Testing (MIT) requirements. This paper presents the laboratory discovery work and the early 3rd party confirmation work. These gels are now being field-tested for waterflood conformance and casing repairs.