bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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

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

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

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

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.
Developing Surfactant to Increase the Production in Heavy Oil Reservoirs
Authors: Khosravi Vahid
Published: July 2010

Micro-organisms are the creatures that in the prepared condition for their growth, they can be beneficial for so many fields. One of these fields is Enhanced Oil Recovery. Microbial enhanced oil recovery method (MEOR) includes the usage of Micro-organisms of their productions.

One of the most important productions of micro-organisms is surfactants. Surfactants include cationic surfactants, anionic surfactants, and neutral surfactants. These conditions have two parts which are water-wet and oil-wet, and by putting their selves in the surface between oil and water, they decrease the interfacial tension, and in this way they help oil flow going towards wells. For instance, one of the problems in the movement of oil inside an environment of porosity is a phenomena which is called pinching off, in which the surfactants decrease the trapped oil and make it continuous, and this makes the diameter of oil molecules decrease to the size smaller than gate diameter, so that the oil molecules start bypassing.

The advantages of these biological combinations compared with their chemical types are as follows: more surface activity, better performance in various temperature conditions, PH, salinity, and being less poisonous. Nc is related to the residual oil saturation through the capillary desaturation curve. The critical capillary number and the shape of the capillary desaturation curve depend on the rock properties

Such as pore size distribution and wettability. The more the Nc, the less the IFT, so the oil recovery gets more.

The high potential of EOR is illustrated in the fact that over %65 of the original oil-in-place still remains in many worldwide reservoirs after primary and secondary oil recovery. Micro-organisms are used in this method to reduce permeability and homogenization of reservoir by sealing the areas with high permeability. Their productions are being used in other fields too; for example biopolymers are used to increase the viscosity of oil, biosurfactants are used to decrease the interfacial tension of oil-water, biogases and solvents are used to reduce the viscosity and organic acids of oil to increase the porosity by solving the carbonate rocks.
Best Practices in Testing and Analyzing Multilayer Reservoirs
Authors: Pan Yan , Sullivan Michael , Belanger David
Published: July 2010

Layered formations are the norm rather than exception among oil and gas reservoirs. Knowing the individual layer properties is important for making development strategies. It plays a significant role in secondary recovery. This paper presents best practices in the design, execution, and analysis of multilayer pressure transient tests in Tengiz oil field in western Kazakhstan. Our experience proves that the use of multilayer testing and analysis techniques results in a lower level of uncertainty in layered reservoir characterization than can be obtained by the simpler commingled pressure transient test alone.

The formations in the platform area of Tengiz consist of multiple zones with different reservoir pressures; therefore cross-flow often occurs during shut-in periods. In some cases, the impact from different layer pressure and skin distribution could result in 100% difference in individual layer permeability estimations. To reduce the uncertainty, the Selective Inflow Performance (SIP) production logging technique (Stewart et al. 1981) is used to measure the bottom-hole pressures and flow contributions of individual layers during a commingled pressure transient test. Pulsed Neutron Capture logs are also used to provide information about stimulation effectiveness (skin) in each zone. Then a robust step by step analysis method developed to use all data and information is applied to obtain individual layer properties. The best practices of using this methodology and the associated uncertainty are discussed in this paper.

The challenge in characterization of layered reservoirs lies in the large number of unknown parameters. The approach described in this paper resolves enough of these unknowns in a systematic fashion that a more direct solution is obtained with resultant lower uncertainty.
Optimizing Volumetric Sweep Efficiency in Waterfloods by Integrating Streamlines, Design of Experiments, and Hydrocarbon F-F Curves
Authors: Izgec O. , Sayarpour M. , Shook G. M.
Published: July 2010

Waterflooding is by far the most commonly used method to improve oil recovery. Success of a waterflood depends on its ability to sweep remaining oil efficiently. Incorrect or insufficient design may lead to increases in cost associated with water cycling and poor sweep. Most waterflood management is restricted to classical methods (e.g., surveillance or pattern balancing) or sensitivity studies centered on finite difference simulation. Most of the time, conventional methods fail to account for subsurface heterogeneity, while optimizing sweep via conventional modeling is time consuming in waterfloods with large number of wells or a relatively high-resolution numerical grid.

We propose a practical and efficient approach for rapid and full-field optimization of waterfloods. Our method focuses on optimizing volumetric sweep efficiency using streamlines. We introduce two new concepts: the Hydrocarbon F-Φ Curve and Hydrocarbon Lorenz Coefficient (LC-HC). We show that these concepts can be easily derived from streamline simulation and can be used for optimum waterflood management. The LC-HC serves as a unique measure of the flow – or dynamic – heterogeneity, and we show that minimizing LC-HC results in optimal volumetric sweep efficiency. The method is straightforward: we evaluate the sensitivity of LC-HC to variations in operating conditions in a design of experiment (DoE) study, describe the LC-HC as a function of those operating conditions using response surface methods, then select the operating conditions that minimize LC-HC (maximize sweep efficiency). The main advantages of our method are its speed, flexibility to start optimizing at any arbitrary time regardless of the history, and ability to handle large problems. The new approach requires running a streamline simulator only a few time steps, so multi-million cell models are optimized in minutes.

We verified our approach with several synthetic examples. An example shows that a 100,000 cell, complex reservoir with 13 wells, and 29 completions can be optimized in less than 4 hours, leading to significant increase in recovery efficiency and reduced water cycling. We then apply the method to a model of the Brugge field, the SPE comparative problem on recovery optimization. Improved production response illustrates the power of the new method.
The Roles of Nano-Scale Intermolecular Forces on the Film Stability During Wettability Alteration Process of the Oil Reservoir Rocks
Authors: Rahbar M. , Ayatollahi S. , Ghatee M. H.
Published: July 2010

The interfacial phenomenon of spreading and adhesion of fluid on the rock surfaces, known as wettability, has serious implication because of their impact on multi phase flow in the rock hence the recovery efficiency of petroleum reservoirs. However, the prediction of wetting properties and its alteration during the production or any chemical treatment processes is difficult because of the complex chemical composition of the crude oil and the formation brine as well as the interaction with the minerals very close to the rock surface. Many practical techniques to assess the wettability of mineral surfaces are available, but these measurements cannot capture the micro mechanism of wetting and the mechanisms of wettability changes. To understand these mechanisms one needs to investigate the interactions that take place between crude oil, brine and rock surfaces close to the solid-fluids boundary. The objective of this work is to present the results of developed software based on the rock-fluids interactions for the prediction of the wettability state in a solid-liquid-liquid system. In this model, macroscopic contact angle and surface wettability are related to the film stability through disjoining pressure isotherm of the wetting phase film separating the solid and non-wetting phase. Besides, the mechanism of wetting changes and predominant surface forces is diagnosed through disjoining pressure. The contribution of van der Waals, electrostatic and structural forces is identified as the main forces to affect the status of the wetting film through disjoining pressure calculation. In this model some efficient parameters such as pH, brine composition, zeta potential, crude oil composition especially its polarity and acid-base number and crude oil refractive index are considered. This model is especially designed to predict the wettability and its alteration for the tight rocks, which is seldom to be done through the laboratory measurements.
New Insight into Integrated Reservoir Management using Top-Down, Intelligent Reservoir Modeling Technique; Application to a Giant and Complex Oil Field in the Middle East
Authors: Kalantari-Dahaghi Amirmasoud , Mohaghegh Shahab D. , Khazaeni Yasaman
Published: July 2010

This paper demonstrates the validity of a recently developed reservoir modeling technique called "Top-Down, Intelligent Reservoir Modeling" (will be referred to Top-Down Modeling for short). This new modeling technology integrates reservoir engineering analytical techniques with Artificial Intelligence & Data Mining (AI&DM) in order to arrive at an empirical, cohesive and spatiotemporally calibrated full field model. The model is used to predict reservoir performance in order to recommend field development strategies. One of the distinctive features of this technology is its data requirement for analysis. Although Top-Down Modeling can incorporate almost any type and amount of data that is available in the modeling process, it only requires monthly production rate and some well log data (porosity, initial water saturation and thickness) in order to start the analysis and provide a full field model. Presence and incorporation of other types of data such as core analysis, pressure data, reservoir characteristics and seismic data can and will increase the accuracy and validity of the developed model.

In this work, we apply Top-Down Modeling to a large and complex Oil field in the Middle East that produces from a combination of clastic and carbonate formations. Production rates and well log data from 210 wells have been analyzed and imported into the Top-Down Modeling software to develop a new empirical reservoir model and make predictions on new well performance and potential infill locations. Results from Top-Down Modeling analyses are compared with results concluded from a comprehensive reservoir management study (that included use of large amount and various types of data and a commercial numerical reservoir simulator) performed by an IOC. Analytical reservoir engineering techniques used in the Top-Down Modeling presented in this study include production decline analysis, volumetric reserve and recovery factor estimations and are integrated with Voronoi graph theory, geostatistics, two-dimensional Fuzzy Pattern Recognition (FPR), and discrete, data driven predictive modeling.

The resulting full field Top-Down Modeling is used to identify the distribution of the remaining reserves, sweet spots for infill locations and under-performer wells and also identify the locations in the reservoir where gas cap is formed. Furthermore, the fullfield model is used to predict new well’s performance.
Modeling Gas-Phase Mass Transfer Between Fracture and Matrix in Naturally Fractured Reservoirs
Authors: Jamili A. , Willhite G. P. , Green D. W.
Published: July 2010

Gas injection in naturally fractured reservoirs maintains the reservoir pressure, and increases oil recovery primarily by gravity drainage and to a lesser extent by mass transfer between the flowing gas in the fracture and the porous matrix. Although gravity drainage has been studied extensively, there has been limited research on mass-transfer mechanisms between the gas flowing in the fracture and fluids in the porous matrix.

This paper presents a mathematical model which describes the mass transfer in one dimension between a gas flowing in a fracture and a horizontal matrix block. The model accounts for diffusion and convection mechanisms in both gas and liquid phases in the porous matrix. The injected gas diffuses into the porous matrix through gas and liquid phases causing the vaporization of oil in the porous matrix which is transported by convection and diffusion to the gas flowing in the fracture. Compositions of equilibrium phases are computed using the Peng-Robinson EOS.

The mathematical model was validated by comparing calculations to two sets of experimental data reported in the literature (Morel et. al. (1990) and Le Romancer et. al. (1994)), one involving nitrogen flow in the fracture and the second with carbon dioxide flow. The matrix was a chalk. The resident fluid in the porous matrix was a mixture of methane and pentane. In the nitrogen diffusion experiments, liquid and vapor phases were initially present, while in the carbon dioxide experiment the matrix was saturated with a liquid phase.

Calculated results match the experimental data, including recovery of each component, saturation profile, and pressure gradient between matrix and fracture. The simulation revealed the presence of countercurrent flow inside the block. Diffusion was the main mass-transfer mechanism between matrix and fracture during nitrogen injection. In the carbon dioxide experiment, diffusion and convection were both important.
A Multivariate Autoregressive Model for Characterizing Producer-producer Relationships in Waterfloods from Injection/Production Rate Fluctuations
Authors: Lee Kun-Han , Ortega Antonio , Jafroodi Nelia , Ershaghi Iraj
Published: July 2010

In this paper we introduce injector-producer models to characterize communications among wells in waterfloods, using only injection and production data. In other proposed modeling approaches, the producers are often assumed to be independent of each other and to be only influenced by nearby injectors. We present an improved technique based on a multivariate autoregressive model with exogenous inputs (M-ARX), which models the interaction among all injectors and producers (including producer to producer interactions) in a region, using a set of linear differential/difference equations.

By coupling all injection/production rates in a region under analysis, the M-ARX model outperforms other models in terms of prediction performance, while requiring a relatively small number of parameters to be estimated. Also, when the rates of some producers are artificially constrained, e.g., due to shutting-in of a producer, the retraining period of our M-ARX model is significantly shorter, as compared to other models. Moreover, model parameters can be interpreted as the producer-to-producer interactions.

Validation under various scenarios using numerical simulated data shows that the M-ARX model outperforms the capacitance model (CM) in terms of forecasting ability and is much more robust to noise than the finite-impulse-response (FIR) model. The M-ARX model provides estimates of the interwell connectivities that are highly consistent with the results obtained from both CM and FIR models.

In addition, the M-ARX model can be extended to higher orders easily, making it possible to handle more complex and heterogeneous scenarios.
Ensemble Based Optimization of EOR Processes
Authors: Odi Uchenna O. , Lane Robert H.
Published: July 2010

The advent of smart well technology has allowed the control of a hydrocarbon field in all stages of production. This holds great promise in managing EOR processes, especially in terms of applying optimization techniques. However, some procedures for optimizing EOR processes are not based on the physics of the process, which can lead to erroneous results. Additionally, optimization of EOR processes can be difficult if there is no access to the simulator code for computation of the adjoints used for optimization. This work is a general procedure for designing an initial starting point for a surfactant flood and water flood optimization. The method does not rely on a simulator's adjoint computation. Instead of using adjoints for optimization, the Ensemble Kalman Filter optimization (Enkfopt) was developed and used to optimize the net present value (NPV) of a 5 spot surfactant flood and water flood process. Additionally, constrained optimization was created and added to the Enkfopt method. The controls were based on surfactant flood and water flood process dynamics and included production control for four producers, injector injection rate, and surfactant concentration. Field permeability, field porosity, and economic inputs were parameters held constant for the optimization. Once the optimal solution was obtained, multiple realizations of the permeability and economic inputs were used to generate a cumulative probability distribution of the NPV. Preliminary results show an improvement of the NPV of the water flood process (up to 60% increase) and surfactant flood process (up to 150% increase). Results also show that the optimized controls retain the same relationship as the original controls. This work provides a method to manage risk by performing an optimization and then using the optimal solution to assimilate possible geological and economic scenarios. Cumulative distribution curves of NPV provide tools in accessing the probability of project success.
Intelligent Model Management and Visualization for Smart Oilfields
Authors: Chelmis Charalampos , Bakshi Amol , Seren Burcu , Gomadam Karthik , Prasanna Viktor K.
Published: July 2010

Simulation models are commonly used as an aid to decision making for oilfield development and operations. Such models represent information uncertainty and alternate operational strategies and form a design space, which is used by engineers to explore different "what-if" scenarios. As the composition of the engineering team changes over the lifetime of the oilfield and new modeling requirements emerge, it becomes important for engineers to be able to quickly "mine" from and understand the distribution of the models in the design space, and also to know if a particular scenario was already modeled in the past or if a new model needs to be created.

In this paper, we describe a technique to analyze arbitrarily large set of simulation models, identify similarities and differences between model parameters, and automatically cluster the models based on similarity in an n-dimensional design space. The major contribution of this work is a vector space based approach for automatic model clustering without human intervention. Building on this contribution, our system provides a smart browse, search and visualization capability over a legacy model catalog in a non-proprietary manner. The system also performs automatic analysis of available models in order to discover their underlying basic structure and, if possible, represents the models as variations of this basic structure. We demonstrate the application of our algorithm to a set of Integrated Production Modeling (IPM) models. However, our use of a standard, non-proprietary network model abstraction as an intermediate representation means that our analysis technique can be applied to models created using a variety of modeling and simulation tools.

The broader significance of this work is in the context of knowledge management for smart oilfields, specifically focused on extracting meaningful information from legacy simulation models, and making this information available and useful to the domain experts.
Investigation of Trapped Oil Mechanisms and Opportunities for Improved Oil Recovery in Deepwater Gulf of Mexico
Authors: Li Xin , Lach Joseph , Mcmillen Kenneth , Duan Shengkai
Published: July 2010

Deepwater Gulf of Mexico oil fields (DW GoM) typically get modest ultimate recovery factors in the 10% - 35% range, because reservoirs tend to be small, deep, and complex. The remaining oil target for Improved Oil Recovery (IOR) is tempting large, with about 30 Billion Bbl estimated to be left in discovered fields at abandonment. Procedures on by-passed oil mechanisms analysis are based on analysis of field data compiled by Minerals Management Service, on data extracted from focused literature reviews, and on original work to analyze by-passed oil mechanisms and describe the remaining oil distribution in turbidite reservoirs of DW GoM.

This paper describes a study on oil trapping mechanism, by-passed oil categories and their distributions. It is key part of study directed at recommending a select group of IOR processes for multi-million dollar research and development funding by Research Partnership to Secure Energy for America (RPSEA).

The performance of 450 oil reservoirs in 83 deepwater Gulf of Mexico fields has been evaluated and characterized by geological setting, reservoir properties, and development constraints. The results have been used to estimate statistically the average oil recovery, prominent reservoir drive mechanisms, oil trapping due to structural and depositional complexity, and reservoir volume not connected to wells. The term "Trapped Oil Mechanisms" is used in this work to define the reasons for projected remaining oil in-place under current operating practices. In this paper we review the detailed assessment of several signicant reservoirs in two fields and then present the overall summary of trapped oil mechanisms for Neogene reservoirs in the deepwater Gulf of Mexico.

The results of this work are being used to define IOR processes targeted at reducing the projected ROIP.
Numerical Modeling of the Water Imbibition Process in Water-Wet Laboratory Cores
Authors: Kalaei M. Hosein , Green Don W. , Willhite G. Paul
Published: July 2010

Oil recovery from water-wet, naturally fractured reservoirs subjected to waterflooding is governed by spontaneous imbibition of water from the fractures into the matrix rock due to capillary and gravity forces, which results in the displacement of the non-wetting oil. Several parameters, such as wettability, boundary conditions, rock geometry, fluid properties, and IFT between oil and water affect the oil recovery.

A three-dimensional, two-phase numerical simulator was developed to investigate both mechanisms of oil production and the parameters that influence recovery in water-wet laboratory cores. The model was validated by a comparison of calculations to the numerical simulation of Blair (1964) and experimental data presented by Schechter (1991) and Fischer and Morrow (2005). Agreement between model calculations and data was excellent.

When capillary forces are negligible, gravity force causes displacement of the oil spontaneously due to density difference between the oil and water in cores mounted vertically. The effect of reducing the interfacial tension between water and oil on oil recovery by spontaneous imbibition was numerically investigated for a wide range of IFT's in cores oriented vertically and compared against experimental data. The study showed that reducing the IFT between oil and water may dominate the gravity segregation and decrease the rate of imbibition in low permeable cores. However, the ultimate recovery increases when compared to the same system with higher IFT. Comparison of the imbibition curves obtained for the same value of oil/water viscosity ratio revealed that imbibition had its lowest value when the one-end, open-boundary condition was applied on the core. Ultimate recovery was almost the same for all other different boundary conditions.
Integration of 3D Seismic Attributes into Stochastic Reservoir Models Using Iterative Vertical Resolution Modeling Methodology
Authors: Wang Jianwei , Dou Qifeng
Published: July 2010

At early stages of field development, there is generally insufficient well data available to predict reasonable reservoir property distributions. Integrating densely distributed seismic attributes as a secondary constraint can significantly improve the accuracy of reservoir models and reduce uncertainties. However, the scale difference between seismic and well log presents a challenge. Geostatistical modelers encounter both upscale and down-scale issues. We illustrate an iterative vertical resolution modeling methodology to compromise both seismic and log resolutions, and a geostatistical modeling workflow for generating better reservoir models.

Vertical variogram analyses on log data were conducted to determine a well log vertical resolution upper-limit for each geological zone. Under this vertical resolution, the heterogeneity of log properties can be preserved. Different 3D reservoir models with different scales were built. Log porosities were upscaled and seismic attributes were sampled (down-scaled) into these models. A correlation coefficient between log porosity and seismic attributes for each zone in each model was calculated. Within the upper-limit of the log resolution, the best vertical scale that compromises both log and seismic scales was identified based on the best correlation. Horizontal variogram analysis was then conducted based on densely sampled correlated seismic attributes. This method overcame the common difficulty in conducting horizontal variogram analysis using aerially-sparse log data and provided an improved quantitative estimate of the spatial correlation. Sequential Gaussian simulation coupled with collocated co-kriging was then used to populate porosity.

The methodology was applied to the Gullfaks field in the North Sea. The workflow described yielded a reservoir model improved over conventional stochastic modeling methods and greatly reduced uncertainties on porosity distribution away from wells. The chief technical contribution is the presentation of an iterative vertical resolution modeling methodology that compromises both seismic and log resolutions to integrate seismic into a reservoir model.