bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Determination of Minimum Miscibility Pressure (MMP) by Gas/Oil IFT Measurements for a Gas Injection EOR Project
Authors: Saini Dayanand , Rao Dandina N. 
Published: July 2010

Abstract
Reliable knowledge of minimum miscibility pressure (MMP) plays a key role in the design and implementation of any miscible gas injection enhanced oil recovery (EOR) project. Various theoretical methods but few experimental methods are available for confidently determining the MMP at reservoir conditions using actual reservoir fluids.
The present experimental study reports on the determination of minimum miscibility pressure (MMP) for recombined live oil with 99.9% pure CO2 at reservoir temperature using the vanishing interfacial tension (VIT) technique. VIT technique relies on the measurements of gas/oil interfacial tension (IFT) at several pressures and reservoir temperature. MMP is then obtained by extrapolation of the measured data to zero interfacial tension. In the present study, IFT between two recombined live oil samples and CO2 was measured at reservoir temperature of 289°F and at several pressures above the bubble point pressure of 2593 psia using the pendant drop method and the capillary rise technique. The pressure was then increased in steps to approach a near zero gas/oil IFT condition. The MMP that corresponds to the pressure of zero IFT was obtained by extrapolating the measured values of gas/oil IFT to zero on IFT versus pressure plot. Such extrapolation yielded MMPs of 3533 psia and 3543 psia for the two recombined live oil samples.
This study was conducted to aid in the implementation of a proposed miscible CO2 flood in a newly discovered oil field in Mississippi by comparing the results of an independently conducted equation-of-state (EOS) modeling study based on vanishing tie-line method. Measured VIT-MMP was slightly lower (~4%) compared to the EOS-estimated dispersion-free MMP (3685 psia). This experimental study reinforces the use of VIT technique as a robust experimental method for determining the MMP and its possible use to validate the EOS models for using them in compositional simulation studies.
Integrated Characterization and Simulation of the Fractured Tensleep Reservoir at Teapot Dome for CO2 Injection Design
Authors: Ouenes A. , Anderson T. , Klepacki D. , Bachir A. , Boukhelf D. , Araktingi U. , Holmes M. , Black B. , Stamp V. 
Published: July 2010

Abstract
This paper describes a workflow that fully utilizes the post-stack seismic attributes to derive reliable geologic and fracture models that are validated with multiple blind wells and reservoir simulation. The first step in the workflow is to run post-stack seismic processes, which includes volumetric curvature, post-stack inversion and spectral imaging. The second step consists of using the various post-stack seismic attributes to derive 3D geologic and fracture models. The third step is to use the derived models in a reservoir simulator to verify the validity of the models.
This workflow was applied to the Tensleep reservoir at Teapot Dome in Wyoming. A large number of post-stack seismic attributes were generated in time and then depth converted within a 3D geocellular grid. These seismic attributes were used as input in REFRACTTM, Prism Seismic fracture modeling software, to create geologic and fracture models. An effective permeability was estimated by using a linear combination of the scaled fracture density and the matrix permeability. Two reservoirs unknowns were estimated by history matching in a black oil simulator: the strength of the aquifer and the scaling factor used to convert fracture density to fracture permeability. Water cut was matched at all the wells, confirming the reliability and accuracy of the derived geologic and fracture models and the usefulness of the workflow. With the derived dynamic model, a compositional simulator was used to test various CO2 injection rates and their effects on the breakthrough time.
Addressing Horizontal Steam Injection Completions Challenges with Chevron's Horizontal Steam Test Facility
Authors: Fram J. H. , Sims J. C. , Sequera A. J. , Mayer T. C. 
Published: July 2010

Abstract
Steam injection profile control is a significant challenge for thermal recovery of heavy oil with horizontal wells. There is no reliable commercially available method for controlling two-phase steam distribution in horizontal laterals. In fact, there is not even a commercial laboratory capable of testing such devices. To address this gap, Chevron constructed a surface horizontal steam injection test facility in the Kern River Field located outside of Bakersfield, California. This facility is used for testing commercial and proprietary devices for improving control of steam distribution along a lateral in a horizontal well. The horizontal steam injection test facility tests the capabilities of a wide range of full-sized downhole completion equipment (tubing and liner flow control devices, tubing/liner and annulus/liner isolation devices) at the surface under precise controlled conditions.
This paper discusses the need for horizontal steam injection wells, steam distribution control, and the current "state-of-the-art" horizontal steam injection completions or, more accurately, the lack of steam profile controls currently available. Also discussed are the three areas critical for controlling the steam profile along a lateral: 1) liner-open hole, 2) liner, and 3) tubing-liner. The capabilities of the test facility, impact of flow regimes, initial test results, and a possible pathway to field deployment of promising technology are also addressed.
Temperature-Induced Fracture Reconsolidation of Diatomaceous Rock During Forced Water Imbibition
Authors: Peng J. , Kovscek A. R. 
Published: July 2010

Abstract
Diatomite reservoirs in California hold roughly 12–18 billion barrels oil in place. This resource is high porosity (35-70%), low permeability (1-10 md), and oil quality is variable. Steam injection is technically feasible to unlock such oil. Our previous laboratory work demonstrated a preferential shift toward water wetness at elevated temperature that enhanced recovery and the tendency of fractures, or other permeable pathways, to reconsolidate or heal during thermal operations. This paper focuses on the latter affect.
We conducted a series of forced water imbibition experiments to study the role of pH, temperature, salinity, and various divalent metal ions on silica dissolution of outcrop diatomite core. An optimal condition for dissolution was obtained. Then, several fractured cores were prepared to study the mechanism of fracture reconsolidation. Fractures were oriented lateral to and normal to flow. Fractured cores were subject to different brine formulations, temperatures, and confining pressures. The experimental results suggest that temperature and pH are the two most important factors impacting silica dissolution of diatomite, in agreement with the literature. Wormholes form during many pore volumes of injection of hot alkaline fluid if basic pH is maintained within rock. As a result, permeability is enhanced and porosity increases. The presence of steam hinders silica dissolution because less aqueous phase is available to carry ions. Fracture healing and rock reconsolidation were observed when fluid was injected at elevated temperature. Tests suggest that both silica dissolution and confining stress are necessary for fracture reconsolidation. Fractures that are not closed by the confining stress do not tend to heal. The proposed mechanism for this process has three steps: (i) aqueous silicate production by silica dissolution, (ii) silicate gelation within the pore space and fracture, and (iii) stress closure of fractures to ensure that deposited silica cements the fracture closed. Given sufficient heating and liquid, fracture reconsolidation happens.
A Critical Assessment of CO2 Injection Strategies in Saline Aquifers
Authors: Delshad M. , Wheeler M. F. , Kong X. 
Published: July 2010

Abstract
There is an overwhelming evidence of increased levels of green house gases such as CO2 in the atmosphere with an urgent need to stabilize the CO2 atmospheric content by storage in geological formations. The main concern in geological storage of CO2 is its long term subsurface retention. Primary containment mechanisms are dissolution in water, reaction with rock, and capillary trapping. Development decisions such as number of injection wells, injection rates, well placement, and the need for water production/reinjection may pose a profound effect on long term storage. A reservoir simulation study was conducted to study several injection schemes to assess the impact on the amount sequestered and the extent of vertical migration. Simulations were performed using the compositional reservoir simulator CMG-GEM (2009). Thermal and geomechanical effects were not considered. Several prototype reservoir geomodels were studied to determine the impact of injection strategy on injectivity, CO2 retention, plume extension, and upward movement to formation top seal. It is demonstrated that the well placement, well completion and injection schemes have strong impact on the amount of residual and dissolved CO2. The CO2 injectivity was severely impaired when water and gas are injected simultaneously.
Comparison of Chemical and Hysteresis CO2 Trapping in the Nugget Formation
Authors: Behzadi S. H. 
Published: July 2010

Abstract
The Moxa Arch Anticline is a regional-scale northwest-trending uplift in western Wyoming and it has been chosen for CO2 capture and storage. The Nugget Sandstone is a deep saline aquifer that has been a candidate for CO2 storage. In this paper we compare the amount of mineral and solution trapping in comparison with dynamic hysteresis trapping based on compositional simulation. To the best of our knowledge this is the first paper to computationally assess the chemical trapping in the Nugget formation and to compare these three trapping mechanisms against each other.
Reaction-path and kinetic modeling of CO2–brine–mineral reactions in the Nugget formation was investigated to probe the factors that affect capacity for CO2 chemical trapping. The solution and precipitation trapping of CO2 are functions of temperature, pressure, CO2 fugacity and brine composition. The geochemical simulation of this system was explored in order to assess how mineralogy might change and the relative importance of mineral and solution trapping phenomena through time. After 30 years, 0.06 g of CO2 per kg of reacted rock is sequestered as mineral phases and solution trapping amounts to 0.11 g/kg rock. In comparison, a recent computational study of the Rose Run sandstone, Ohio indicates a much higher (30 times higher) mineral trapping capacity, mainly because of the presence of glauconite as an iron source for siderite formation. The total hysteresis trapping in our study is 0.14 g/kg rock based on compositional simulation for the same period of time.
These results reveal that mineral trapping in the Nugget formation is not significant but that total chemical trapping might be as high as 80% of hysteresis trapping. Therefore, the contribution and importance of chemical trapping in CO2 sequestration should be taken into account for assessment of CO2 sequestration.
Mechanics and Up-Scaling of Heavy Oil Bitumen Recovery by Steam-Over-Solvent Injection in Fractured Reservoirs (SOS-FR) Method
Authors: Singh R. , Babadagli T. 
Published: July 2010

Abstract
Recently, the steam-over-solvent injection in fractured reservoirs (SOS-FR) method was proposed as a potential solution for efficient heavy-oil/bitumen recovery in oil-wet naturally fractured reservoirs. The method is based on initial injection steam (Phase-1), followed by solvent (Phase-2). In the third cycle (Phase-3), steam is injected again to recover more oil and retrieve the solvent. Solvent retrieval during the third cycle was observed to be very fast if the temperature is around the boiling point of the solvent. This process is controlled by efficient matrix recovery and the mechanics of the process needs to be clarified to further determine the efficient application conditions for the given matrix and oil characteristics.
Single matrix behavior during the process was numerically modeled for static conditions and the results were matched with the experimental observations. The physics of the recovery mechanism was analyzed through visual inspection of saturation and concentration profiles in each cycle. The major observation was the substantial effect of gravity in oil recovery when the matrix was exposed to solvent. Special attention was given to the solvent retrieval rate and amount in Phase-3 and the permeability reduction due to asphaltene precipitation in Phase-2. This phenomenon was modeled using a permeability function changing with spatial coordinates and time, i.e. k=f(x, y, z, t). It was observed that permeability reduction due to asphaltene precipitation is significant and needs to be taken into account in modeling the process.
After showing the effect of the matrix size on the oil recovery and solvent retrieval, an up-scaling analysis was performed. The log-log relationship between the time value to reach ultimate recovery and the matrix size yielded a straight line relationship with a non-integer exponent less than two for all three phases of the process. The observed straight line relationship (and the exponent values obtained) is highly encouraging to extend the study to obtain a universal scaling relationship.
Using Second Derivative of Transient Pressure in Welltest Analysis of Low Permeability Gas Reservoirs
Authors: Bahrami Hassan , Reza Rezaee M.. , Kabir Akim , Siavoshi Jamal , Jammazi Rochdi 
Published: July 2010

Abstract
Welltest interpretation requires diagnosis of reservoir flow regimes in order to determine the basic reservoir characteristics such as average reservoir permeability and skin factor. Due to wellbore storage effect, wellbore phenomena and complexity of reservoir response from heterogeneous reservoir layers, detection of the reservoir flow regimes using standard welltest diagnostic plots might be challenging and have some uncertainties.
In pressure transient testing, there are instances where the flow regimes might not clearly be revealed on diagnostic plots of pressure build-up and its derivative, such as incomplete pressure build-up tests, low permeability reservoirs and multi-phase producing wells. In such cases, the Semi-Log plot of first and second derivative of transient pressure versus time can be used to reduce the uncertainties associated with welltest analysis.
This paper describes a new method for well test interpretation using second derivative of transient pressure. Two field examples are shown in which a reliable radial flow regime on pressure build-up data could not be detected using standard plots. The second derivative approach was used to predict radial flow regime trend and estimate the reservoir permeability and skin factor, which the results were in good agreement with production data in these wells.
Integrated Analysis to Optimize Hydraulic Fracturing Treatment Design in a Clastic and Carbonate Formation in Torunos Hydrocarbon Field, Barinas: Apure Basin, Southwest Venezuela
Authors: Castillo L. M. , Jablonoskwi C. J. , Olson J. E. 
Published: July 2010

Abstract
Three hydraulic fracturing have been performed in the Torunos field of southwest Venezuela. One was executed in the Gobernador "A/B" formation in which the fracture reached a water zone located nearby. The other two treatments were performed in the Escandalosa "O" formation. Placing the proppant into this formation was problematic owing to propagation of multiple hydraulic fractures and excessive leak-off. Today, several wells are inactive because of low productivity. Such wells could be potential candidates for reactivation by hydraulic fracturing if the problems encountered in previous treatments can be avoided. Therefore, the purpose of this study is to optimize the design of hydraulic fracturing treatments in the formations under consideration while avoiding the problems encountered in the previous attempts. Experimental design and response surface methods were used to perform sensitivity analyses and to evaluate uncertainty to optimize the design of hydraulic fracturing treatments. Experimental design was used to generate a reduced number of cases with simultaneous combinations of uncertain variables. Simulation of the cases generated was then performed, assisted by a commercial simulator. Response surface method was used to develop surrogate equation models that fit the simulation responses. Monte Carlos analysis was performed to estimate the probability distribution function of the propped fracture length, propped fracture height, depth to the fracture bottom, and net present value (NPV) to select the optimum designs based on technical, economical, and risk analyses. The results show that the optimum hydraulic fracturing treatment design for the Gobernador "A/B" formation should involve small slurry volume (around 300 bbl), a low injection rate (between 6 bbl/min and 8 bbl/min), and low viscosity crosslinked fluid (20 cp). This will control the fracture height and avoid fracturing the water zone. Moreover, reducing the perforated interval to around 20 ft and using low density shot (1 SPF) will help to minimize the propagation of multiple hydraulic fractures in the Escandalosa "O" formation. Finally, the optimum injection rate and slurry volume in this formation are 20 bbl/min and 800 bbl respectively.
Modeling the Toe-to-Heel Air Injection Process by Introducing a New Method of Type-Curve Match
Authors: Jabbari Hadi , Kharrat Riyaz , Zeng Zhengwen , Mostafavi Vahid , Emamzadeh Abolghasem 
Published: July 2010

Abstract
Toe-to-heel air injection (THAI), a method of in-situ combustion, was studied in this research. The temperature distribution was analytically formulated and compared to the experimental data. The objective of this study was to investigate the application of horizontal wells to thermal recovery via the gravity drainage mechanism, both analytically and experimentally. To do so, first, the differential equations of heat transfer around the moving burning front in a vertical combustion tube were derived. Solutions of those equations were obtained. Then, the recorded temperatures within the combustion tube were compared to the results of the analytical model. Finally, new "type-curves" were generated for approximating the front velocity factor which seemed to be applicable to process optimization.
A New Practicable Method to Determine the Optimal Well Ratio of Injection to Production Considering the Influence of the Natural Water Influx
Authors: Nie R. , Jia Y. , Huo J. , Chen L. , Shi G. , Lu J. , Zhang T. 
Published: July 2010

Abstract
For the artificial water flooding development reservoir that maybe has strong natural edge water and bottom water, it is very important to determine the optimal well ratio of injection to production considering the influence of the natural water influx in the design of reservoir development plan. No good reservoir engineering method is found to determine it. A new practicable method is presented: the optimal well ratio of injection to production is the well ratio that can make the reservoir being able to obtain the maximum ability of liquid production rate. According to the material balance principle, the liquid production is equal to the sum of the water injection and the water influx, so the objective function of the maximum amount of liquid production rate is established after a series of deriving and deduction of complex formulas, and then the optimal well ratio of injection to production is deduced under the conditions of meeting the objective function maximum. It is found that the optimal well ratio of injection to production is the function that is related to the bottomhole flowing pressure of injection well and production well, water injectivity index, fluid productivity index, the number of the whole reservoir wells, the natural aquifer body pressure and the natural water influx coefficient. It is also found that the well ratio of injection to production when the natural water influx coefficient is zero is just the well ratio of injection to production in injected and produced fluid balance. In the end, the optimal well ratio of injection to production is successfully calculated under different bottomhole flowing pressure conforming to the bottomhole flowing pressure limitations of injection well and production well for an example reservoir in Xinjiang oilfield. The results available can be used in guidance and reference to the next development adjustment, and this method can be applied to any reservoir with natural water influx and artificial water injection.
Heavy Oil Production Enhancement by Viscosity Reduction
Authors: Shuler Patrick , Tang Yongchun , Tang Hongxin 
Published: July 2010

Abstract
This paper presents an evaluation of different chemical agents that can reduce dramatically the apparent viscosity of a heavy crude oil or a thick emulsion. The focus of this study is on methods to improve the production of heavy oils and very viscous emulsions such as are found in California, Canada, and Venezuela. This study identified several surfactant-demulsifier formulations that can reduce the viscosity of such heavy fluids by as much as 3 orders of magnitude.
If efficient chemical solutions are applied downhole to reduce produced fluids viscosity this offers an economical means to reduce the energy required to move the oil between the well to the surface facilities, thereby improving well productivity and reducing lifting costs. It is especially suited for wells that are producing fluids at colder temperatures (less than 150 °F) that have extreme fluid viscosities (from 10,000 to 100,000 cp); these may be reduced to 100 – 500 cp by gentle mixing with aqueous-based chemical treatment solutions. Wells with high hydraulic pressures, poor pump efficiencies, or excessive pressure losses in the facility gathering systems are good candidates for these treatments. Reducing these extreme viscosities will have benefits such as lowering the power consumption to lift the produced fluids and reduce system pressures. Chemical costs for such chemical treatments are less than a dollar a barrel of oil, and can be even less than $0.50 per barrel of heavy oil.
These same or similar chemical systems also may be beneficial for longer distance transportation of heavy oils, as pretreatments for cyclic steam treatments, or as additives in the stimulation fluids applied in heavy oil wells.
This laboratory investigation employed a unique novel viscometer that will measure accurately the effective dynamic viscosity of multi-phase liquids (emulsions) from several centiposes to thousands of centipoise. This instrument was developed to overcome the limitations of conventional laboratory viscometers to measure unstable emulsions that may separate during the measurement process.