bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Coalbed Methane Water to Oil Recovery by Low Salinity Waterflooding
Authors: Pu H. , Xie X. , Yin P. , Morrow N. R.
Published: April 2008

Development and production of coalbed methane involves the production of large volumes of water. The salinities and sodium adsorption ratios of coalbed methane (CBM) water from the Powder River Basin range from 370 to 1,940 ppm and 5.6 to 69 respectively. Surface discharge of CBM water can create serious environmental problems; subsurface injection is generally viewed as economically nonviable. It has been shown that oil recovery from reservoir sandstones can be improved by low salinity waterflooding for salinities ranging up to 5,000 ppm. There may be both technical and regulatory advantages to application of CBM water to oil recovery by waterflooding. Thin section and scanning electron microscope studies of the mineral constituents and distribution of Tensleep and Minnelusa sandstones show they are typically composed of quartz, feldspar, dolomite and anhydrite cements but have very low clay content. The sands contain interstitial dolomite crystals in the size range of up to about 10 microns. Three sandstone cores from the Tensleep formation in Wyoming were tested for tertiary response to injection of CBM water. The cores were first flooded with high salinity Minnelusa formation brine of 38,651 ppm to establish residual oil saturation. Synthetic CBM water of 1,316 ppm was then injected. Tertiary recovery by injection of CBM water ranged from 3 to 9.5% with recoveries for all but one flood being in the range of 5.9 to 9.5%. Previous studies showed that the presence of clay was needed for response to low salinity flooding. As a test of the recovery mechanism, a Tensleep core was preflushed with 15% hydrochloric acid to dissolve the dolomite crystals. The treated core showed no tertiary recovery or pressure response to CBM water.
Residual Oil Saturation from Polymer Floods: Laboratory Measurements and Theoretical Interpretation
Authors: Huh Chun , Pope Gary A.
Published: April 2008

A detailed analysis of the laboratory corefloods and their simulation matches, carried out earlier in our laboratory, show that, while a tertiary polymer flood cannot mobilize the waterflood residual oil, a secondary polymer flood can displace oil below the waterflood residual oil saturation observed in the same core. We show with a simplified pore-level modeling study that, when a viscoelastic polymer solution surrounds a mobile, funicular oil column in a chain of pores and slowly drains it, the breakage of the oil column into oil ganglia is delayed by the polymer's elasticity resisting the deformation of the oil/water interface.

The residual oil saturations from waterflood and a subsequent (i.e., tertiary) polymer flood were measured in homogeneous Berea sandstone cores and in Antolini sandstone cores with small-scale heterogeneity, by Wreath (1989) and Wang (1995). For the latter, the distributions of porosity/permeability in the core samples were measured with mini-permeameter and CAT scan, and were employed as input for the history-matching simulations. The residual oil saturations from waterflood and a secondary polymer flood in the same core were also measured in Berea and Antolini cores. For both Berea and Antolini cores, a tertiary polymer flood did not reduce the waterflood residual oil saturation. For nine Antolini cores, a secondary polymer flood reduced the residual oil saturation below the waterflood value by 0.02–0.22 in saturation units. To investigate whether the differences observed for the heterogeneous Antolini cores are due entirely to the improved volumetric sweep or due also to the true reduction in residual oil saturation, history-matching simulations have been carried out by Lu (1994). The secondary polymer flood results could be matched only when its residual oil saturation value is lower than that for waterflood. Therefore, the higher oil recovery from the secondary polymer flood is the result of combination of improved sweep and the reduction in residual oil saturation.

In order to model the delay of the oil column breakage into oil ganglia qualitatively, we consider a circular oil column surrounded by an annulus of a polymer solution in a circular tube. Assuming that the polymer solution can be modeled as a Maxwell fluid which has both viscous and elastic rheological character, the stability of the oil column is analyzed in terms of the fluid properties and the tube and oil column radii. While the interfacial tension between oil and polymer solution make a long oil column become unstable and break into oil droplets, the elasticity of the polymer solution resists the deformation of the interface. Calculation of the growth rate for the interfacial disturbance shows that, as the elastic modulus of the Maxwell fluid increases, the growth rate decreases, suggesting that the oil column could become thinner, thereby potentially decreasing the residual oil saturation.
Overview of the Illinois Basin's Sequestration Pilots
Authors: Frailey Scott M. , Finley Robert J.
Published: April 2008

As part of the DOE's Phase II and III Geologic Sequestration Partnership program, the Illinois State Geological Survey is leading the Midwest Geologic Sequestration Consortium (MGSC) in various field demonstrations. MGSC's Phase IMII is six sequestration pilots of which there are four EOR pilots, one S/ECBM pilot and one, large-scale brine-saturated formation injection pilot.

A small 43 ton single well, huff-and-puff has been designed, implemented and completed in the Loudon oilfield. The well was a single formation completion at 1500 ft at pressure and temperature considered immiscible. The well's initial oil response was 8x the pre-CO2 oil rate. The site selection, equipment layout, test results and background information will be presented.

Selection of a pattern flood is in the late part of the screening process. Because of the relative low reservoir temperatures and high fracture gradient, this pilot is being designed as a liquid CO2 flood. Model results suggest 6–8 months of continuous injection followed by 2–3 months of water injection are required to have a measurable response at this site. Finalization of pilot contract with oilfield operator and UIC permit application process is being initiated at this time. The plans for the remaining two EOR pilots are similar to the pattern flood except these sites will be screened for pressure and temperature conducive to immiscible and traditional miscible conditions.

The S/ECBM pilot is scheduled for injection in summer of 08. Presently two wells in the pilot have been drilled, cored and DST'd. DST permeability results were lower than expected and drilling was suspended in order to carry out additional pressure transient testing including two falloff tests and one pulse tests. Results of the PTA tests confirmed the DST results and subsequent suggest closer well spacing is required.

The deep saline formation test is scheduled to have the injection well drilled in spring 08. The UIC permit application has been submitted. This one million ton injection project is intended for the Mt. Simon sandstone in central Illinois; the Mt. Simon is the deepest sedimentary formation in the Basin.
Scaled Physical Model Experiments to Characterize the Gas-Assisted Gravity Drainage EOR Process
Authors: Sharma Amit P. , Rao Dandina N.
Published: April 2008

The year 2006 marks the first time the gas injection EOR production has surpassed that of steam injection processes in the US, signifying the growth of gas injection as a mature technology. In order to control the rising tendency of injected gas in horizontal floods, the water-alternating-gas (WAG) process has generally been the mode of operation in many fields. In spite of its wide application, the WAG process has not lived up to its expectations with reported recoveries in the range of 5–10% OOIP. In order to improve recoveries, we have been attempting to develop the gas-assisted gravity drainage process at LSU. This paper summarizes the effort of conducting scaled physical model experiments in a visual glassbead-packed model aimed at discerning the influence of some scaled dimensionless parameters, such as the capillary number, Bond number and gravity number, on the GAGD process performance.

A 2-D physical model, of 16″ X 24″ X 1″ dimensions, packed with uniform glass beads, was used to conduct visual experiments. These experiments were so designed as to mimic the dimensionless parameters observed in some field projects. The secondary mode GAGD floods yielded recoveries up to 80% OOIP. Additionally, the recoveries displayed a semi-logarithmic relationship with gravity number (ratio of gravity to viscous forces). Interestingly, this relationship was observed to hold good for the high-pressure GAGD corefloods and even the field production data from gravity-stable gas injection projects conducted in pinnacle reefs. A multi-variable regression analysis of the laboratory as well as field data indicated that the Bond number, being the ratio of gravity to capillary forces, had a greater influence on GAGD performance than other parameters. In addition to the observed high recoveries, our attempts to relate the model run times to field project durations, through dimensionless time considerations, have indicated reasonably good rates of production when GAGD process is implemented in field projects.
Full Field Streamline Tracing in Complex Faulted Systems with Non-Neighbor Connections
Authors: Jimenez Eduardo A. , Datta-Gupta Akhil , King Michael J.
Published: April 2008

Full field flow simulators utilize a variety of cell geometries ranging from simple rectangles to complex corner point systems. One of the benefits of corner-point cells is the ease with which we may represent faulted reservoirs. Each face of a cell may be juxtaposed to two or more cells, depending on the fault throw and the lateral displacements of adjacent cells. Conventional finite-difference approaches routinely include the flux between these cells as "non-neighbor" connections. Other examples of non-neighbor or non-standard connections occur at the boundary of local grid refinement (LGR) or local grid coarsening (LGC) regions where two computational grids come into juxtaposition. In each of these instances, the velocity across the non-standard faces of a cell will be unevenly distributed according to the non-neighbor fluxes. In contrast, the standard streamline velocity interpolation model (Pollock's scheme) used within a cell assumes that the flux be evenly distributed on each cell face, inconsistent with the non-neighbor connection fluxes. Streamlines traced with such an approach do not have sufficient degrees of freedom to be consistent with the finite-difference fluxes, and consequently will not follow a physical flow path.

We propose a strategy that provides a consistent representation for streamlines and velocities near faults and non-neighbor connections. Our approach is based on a simple local (boundary layer) refinement construction that can be used to honor the fluxes at each face, without impacting the representation of flow within the cell or on any other cell face. The local refinement construction is the simplest extension to three dimensions for faulted reservoir cells which provides consistency with the finite difference flux calculation. Several examples will be presented for a single pair of cells juxtaposed across a fault and at LGR boundaries to illustrate the difficulties in conventional tracing algorithms and the benefits of our approach. The practical utility of our algorithm is demonstrated in a structurally complex and heavily faulted full field model. The reservoir geometry includes multiple cells with complex fault juxtaposition and several non-neighbor configurations in different faces. This treatment is contrasted with the usual approach and the implications for reservoir scale fluid flow tracing by streamlines is examined
Investigation of Field Scale Dispersion
Authors: John Abraham K. , Lake Larry W. , Bryant Steven L. , Jennings James W.
Published: April 2008

Dispersivity data compiled over many lengths show that values at typical interwell distances are about two to four factors of ten larger than those measured on cores. Such large dispersivities may represent significant mixing in the reservoir or they may be a result of convective spreading driven by permeability heterogeneity. The work in this paper uses the idea of flow reversal to resolve the ambiguity between convective spreading and mixing. We simulate flow reversal tests for tracer transport in several permeability realizations using particle tracking simulations (free from numerical dispersion) on three-dimensional, high resolution models at the field scale.

We show that convective spreading, even without local mixing, can result in dispersion-like mixing zone growth with large dispersivities because of permeability heterogeneity. But for such cases, the dispersivity estimated on flow reversal is zero. With local mixing (diffusion or core scale dispersion) the dispersivity value on flow reversal is non-zero and also much larger than typical core values. Layering in permeability, while increasing the convective contribution to transport, also enhances mixing by providing larger area in the transverse direction for diffusion to act. This suggests that in-situ mixing is an important phenomenon affecting the transport of solutes in permeable media even at large scales. Dispersivity values increase with scale mainly because of the increase in the correlation in the permeability field but they could also apparently appear to do so because the Fickian model fails to capture the mixing zone growth correctly at early times.

The results and approach shown here could be used to differentiate between displacement and sweep efficiency in field scale displacements, to ensure accurate representation of dispersive mixing in reservoir simulation and to guide upscaling workflows. The flow reversal concept motivates a new line of inquiry for lab and field scale experiments.
Development of High-Performance Surfactants for Difficult Oils
Authors: Zhao Ping , Jackson Adam C. , Britton Chris , Kim Do Hoon , Britton Larry N. , Levitt David B. , Pope Gary A.
Published: April 2008

We present results for high molecular weight internal olefin sulfonate (IOS) surfactants that show excellent performance when tested using several crude oils with characteristics such as high wax content and viscosity that have made it very difficult to achieve high oil recovery with most surfactants used in the past. High carbon number internal olefin sulfonates when used with appropriate co-surfactants, co-solvents and alkali show the type of phase behavior and ultra-low interfacial tension needed for almost 100% oil recovery in cores. This work shows how the performance of both surfactant-polymer and alkaline-surfactant-polymer flooding can be dramatically improved at the same or lower cost than with conventional surfactants and applied over a wider range of reservoir conditions. High carbon number internal olefin sulfonate surfactants gave good performance at low concentrations and were found to be compatible with both polymers and alkali such as sodium carbonate when used with appropriate co-solvents. The extremely efficient and effective approach for finding high performance surfactants that we previously presented for light crude oils has now been successfully extended to heavier crude oils. The identification of high-performance surfactants suitable for high-temperature and/or paraffinic oil applications opens up the potential to recover a vast amount of additional oil outside the range of conditions considered practical in the past.
Modelling CO2 Injection: IOR Potential after Waterflooding
Authors: Berenblyum R. , Calderon G. , Kollbotn L. , Surguchev L. M.
Published: April 2008

This paper combines the knowledge and experience accumulated at the International Research Institute of Stavanger (IRIS) over a number of years, based on several case studies involving the Tjelbergodden CO2 value chain, modelling of CO2 injection at the Ekofisk field (fractured chalk reservoir) and Gullfaks CO2 injection compositional study.

The paper discusses the importance of correctly representing the physical effects when modelling miscible or immiscible CO2 injection in sandstone and carbonate reservoirs. The following aspects were evaluated:

Transfer of CO2 from fractures to matrix involving diffusive, gravitational and capillary forces; Viscous effects; Formation of low and high concentration liquid hydrocarbon phases; Compositional effects such as miscible displacement and oil swelling; Chemical interaction between CO2, formation or injection water and reservoir rock.

The sensitivity and importance of these effects were studied on several simplified mechanistic models and later applied to actual field cases.

An overview of viscous fingering effects is presented. Results from mechanistic studies of the CO2 matrix-fracture transfer are shown and physical effects are discussed. The paper also presenets critical aspects of Equation-Of-State (EOS) modelling and PVT experiments necessary for a CO2 flood simulation study. From our experience we suggest a "cooking recipe" for building reservoir simulation models for CO2 based IOR process evaluations. Case studies of the CO2 and CO2-WAG IOR methods for reservoirs on the Norwegian Continental Shelf (NCS) are presented and oil recovery potentials of these IOR processes are discussed.
The Effect of Including Tracer Data in the EnKF Approach
Authors: Valestrand Randi , Sagen Jan , Nævdal Geir , Huseby Olaf , Forghany Saeed
Published: April 2008

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

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

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

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

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

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

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

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

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

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

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

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

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.
Compositional Parametrization for Multi-phase Flow in Porous Media
Authors: Voskov D. V. , Tchelepi H. A.
Published: April 2008

In this work we generalize the Compositional Space Parameterization (CSP) approach, which was originally developed for two-phase compositional problems. The extension is valid for an arbitrary number of phases, regardless of the number of components. The compositional space is considered to be a high-dimensional simplex, and the phase behavior is represented using a low dimensional tie-simplex parameterization. For example, in the three-phase case, the space is parameterized using tie-triangles and tie-lines for three- and two-phase regions, respectively. This parameterization improves the accuracy of the phase behavior representation as well as the efficiency of various types of computation for compositional flow. One application of this approach is to speed up standard multi-component phase behavior computations. For general purpose compositional simulation, Compositional Space Adaptive Tabulation (CSAT) can be used to avoid most of the redundant Equation of State calculations. A Supercritical State Criteria algorithm, which is based on adaptive tabulation of the critical tie-simplex, is used to handle the super-critical region. Results of several challenging tests of practical interest indicate that the CSAT strategy is quite robust, and that it leads to an order of magnitude gain in computational efficiency. This strategy is valid for systems with any number of phases and components. Another application area for our CSP framework is to speed up standard thermodynamic computations for complex mixtures. For such systems, the methodology is generalized in terms of a multi-phase tie-simplex description, where one finds the closest tie-simplex and uses it as an initial guess for the computations. For better tie-simplex estimation, interpolation based on triangulation is used. For cases with wide variation in pressure and temperature, linear interpolation of the tie-simplex for these variables is adequate. The methodology is demonstrated using several challenging examples.
Upscaling of Capillary Trapping Under Gravity Override: Application to CO2 Sequestration in Aquifers
Authors: Juanes R. , MacMinn C. W.
Published: April 2008

We present a sharp-interface mathematical model of CO2 migration in saline aquifers, which accounts for gravity override and capillary trapping. The major differences with respect to previous investigations is that we model the shape of the plume during the injection period, we account for regional groundwater flow during the post-injection period, and we introduce rigorously the reduction in water mobility due to trapping of the CO2.

The model leads to a nonlinear advection-diffusion equation, in which the diffusive term is due to buoyancy forces, not physical diffusion. The three key dimensionless groups are the mobility ratio between the injected and initial fluids (M), the gravity number (Ng), and a newly defined trapping coefficient (Г). For the case of interest in geological CO2 storage, in which the mobility ratio is much smaller than 1, the solution is largely insensitive to the value of the gravity number. Under these conditions, the mathematical model can be simplified to a hyperbolic model.

We present a complete analytical solution to the hyperbolic model that includes the injection, early post-injection, and late post-injection periods. Despite the fact that the solution involves the interaction of a sharp imbibition front with a drainage rarefaction front, it admits a closed-form expression. The main outcome of the analytical developments presented here is a formula that predicts the ultimate footprint on the CO2 plume, and the time scale required for complete trapping. Both quantities depend strongly on the shape of the plume at the end of the injection period, which must—therefore—be modeled.

A second application of the analytical solution is a formulation for upscaling the capillary trapping coefficient from the laboratory scale to the basin scale. Explicit expressions are given for the megascopic and gridblock-effective trapping coefficients, as functions of the local trapping coefficient, the mobility ratio, and the grid resolution. Although the expressions derived are based on a one-dimensional sharp-interface model, we anticipate that they will have broader applicability to injection scenarios with unfavorable mobility ratio and dominated by gravity override.
In Situ Phase Pressures and Fluid Saturation Dynamics Measured in Waterfloods at Various Wettability Conditions
Authors: Brautaset A. , Ersland G. , Graue A.
Published: April 2008

During waterfloods of a total of six outcrop chalk core plug samples prepared at various wettabilities, simultaneous local pressures and in situ fluid saturation from Magnetic Resonance Imaging (MRI) intensities were measured. Complementary use of high spatial resolution fluid saturation imaging and phase pressure measurements allowed calculations of the relative permeability to water and the dynamic capillary pressure curves for the imbibition process. One objective was to validate the theory for relative permeability calculations based on data from the fluid phase pressures measured separately using semi-permeable discs and local in situ fluid saturation measurements. A second objective was to identify fluid saturation changes due to spontaneous imbibition and viscous displacement, respectively, to determine the local recovery mechanism and allowing local recovery factors and in situ Amott-Harvey indices to be measured.

The analysis of the experimental data from three of the core samples shows that the presented theory only applies for the saturation interval when the pressures are measured in the same phase. A new and improved experimental setup is therefore introduced for the remaining three cores in order to measure each of the dynamic phase pressure gradients separately using semi-permeable discs located at fixed pressure ports. The obtained data contributes to improved description and understanding of multi-phase fluid flow in porous media, including in situ measurements of relative permeabilities, capillary pressure curves, wettability distribution and local oil recovery mechanisms.
Mechanistic Interpretation and Utilization of Viscoelastic Behavior of Polymer Solutions for Improved Polymer-Flood Efficiency
Authors: Delshad Mojdeh , Kim Do Hoon , Magbagbeola Oluwaseun A. , Huh Chun , Pope Gary A. , Tarahhom Farhad
Published: April 2008

There are increasing laboratory and field evidences that the viscoelastic characteristics of polymer solutions help improve polymer-flood efficiency. Extensive rheological measurements and laboratory corefloods with partially hydrolyzed polyacrylamide polymers with very high molecular weight were carried out to delineate the role of their viscoelastic behavior in improving oil recovery from polymer flood. Different polymer solution's elastic contribution is modeled in the polymer's apparent viscosity in porous media, which is implemented in UTCHEM simulator for quantification of improved reservoir sweep.

As the application range of polymer flood is extended to recover more viscous oils with use of polymers at high concentrations and with very high molecular weights, a mechanistic understanding of polymer rheology in porous media and accurate numerical modeling are essential for successful field implementation of polymer flood.

Oscillatory and shear viscosity measurements and polymer flow coreflood experiments were carried out for different shear rates (and flow velocities and permeabilities in core), polymer concentrations, and molecular weights. The polymer's shear-thickening characteristic was correlated with the Deborah number via its molecular relaxation time, which is in turn determined from the rheological data. An apparent viscosity model that accounts for both shear-thinning and shear-thickening behavior of polymer in porous media was developed, which fit the laboratory data well. The model was then implemented in a compositional chemical flooding simulator and successfully history-matched published coreflood oil recovery experiment.

Through systematic rheological measurements and corefloods, and their use in the apparent viscosity model for simulation, the elastic contribution of different polymers in improving polymer-flood efficiency is quantified. Specifically, a polymer solution's shear-thickening behavior is characterized in terms of the molecular relaxation time determined from bulk rheology measurements.