bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Single-Shot Method for Capillary Pressure Curve Measurement Using Centrifuge and Quantitative Magnetic Resonance Imaging
Authors: Chen Q. , Balcom B. J. 
Published: December 2007

Abstract
The centrifuge method for capillary pressure curve measurement involves increasing the centrifuge speed in steps and measuring the liquid expelled from a short core plug, at equilibrium, for each step. However, the traditional methods for deducing approximate solutions for the capillary pressure curve are based on the assumption that the capillary pressure is zero at the outflow end of the core. In addition, the traditional centrifuge methods for capillary pressure measurement are time consuming. A full capillary pressure curve requires approximately 10 different rotational speeds. We have observed for most sedimentary rocks that the experimental magnetic resonance free induction decay is single exponential and the effective transverse relaxation time (T2*) is largely insensitive to fluid saturation. These features ensure that Centric Scan SPRITE (single-point ramped imaging with T1 enhancement) is a quantitative magnetic resonance imaging (MRI) method, since its local image intensity is directly proportional to the local fluid content. We propose a single-shot method to measure the capillary pressure curve of a long rock core using a single-speed centrifuge experiment and one-dimensional Centric Scan SPRITE MRI to determine the fluid saturation distribution, S(r), along the length of the core. A full capillary pressure curve can be directly determined by the relation of S(r) and the capillary pressure distribution, Pc(r), along the length of the core.
The single-shot method, employing a desktop centrifuge and a desktop permanent magnet based one-dimensional MRI instrument, has been applied to measure the primary drainage, imbibition, and secondary drainage capillary pressure curves for reservoir rocks.
The proposed method for determining the capillary pressure curve is rapid, cheap, and precise. The capillary pressure curve can be obtained straightforwardly with about 40 data points. The duration of the experiment is approximately 10 times less than the traditional method. Since only a single moderate rotational speed is employed, the outflow boundary condition can be maintained, and the effect of gravity can be neglected. In addition, the long rock cores employed for the single-shot method result in a relatively small radial effect.
EOR Field Experiences in Carbonate Reservoirs in the United States
Authors: Manrique E. J. , Muci V. E. , Gurfinkel M. E. 
Published: December 2007

Abstract
A considerable portion of the world's hydrocarbon endowment, and even more so if resources from the Middle East are excluded, are in carbonate reservoirs. Carbonate reservoirs usually exhibit low porosity and may be fractured. These two characteristics in addition to oil-to-mixed wet rock properties usually results in low recovery. When enhanced oil recovery (EOR) strategies are pursued, the injected fluids will likely flow is through the fracture network, bypassing oil in the rock matrix. The high permeability in the fracture network and its low equivalent porous volume result in early breakthrough of the injected fluids. Infill drilling programs and well conformance strategies, mostly gas and water shutoff, have been effectively used to mitigate the early breakthrough and increase oil recovery. However, in most cases, 40 to 50% of the original oil in place (OOIP) is not produced.
A large number of EOR field projects in carbonate reservoirs have been reported in the literature since the early 70's. The field projects showed the technological capability to increase oil recovery and estimated long run costs for their operation. This increase in oil recovery would directly result in additional reserves extending the productive life of the different assets. However, the technical results were not matched by their economic viability given the price environment of the time. In some cases high upfront investments created insurmountable barriers for the technology's application despite the promise of higher returns. In other cases, the high marginal costs eliminated all benefits from the increased recovery. The latter was especially true for EOR processes based on chemical and thermal methods. Over the last three decades, many improvements have reduced the cost per incremental barrel as will be seen below. Carbon dioxide flooding (continuous or alternating with water-WAG) is the dominant EOR process in the United States, mostly due to the availability of appropriate CO2. CO2 EOR is also the stepping stone towards sequestering carbon which could become a future business opportunity if carbon trading ever is implemented.
This paper presents an overview of EOR field experiences in carbonate reservoirs in the United States, an analysis of recent efforts and discusses briefly on new opportunities for novel chemical methods. The main EOR experiences reviewed are CO2 injection, polymer flooding, steam injection and in-situ combustion (air injection).
Experimental and Modeling Study of the Transport of Chromium Acetate Solutions Through Carbonate Rocks
Authors: Chen F. , McCool C. S. , Green D. W. , Willhite G. P. 
Published: December 2007

Abstract
The transport of chromium acetate solutions through dolomite rock material was studied by injecting various solutions through short dolomite cores and measuring Cr, Mg, and Ca concentrations and pH in the effluent. A mathematical model was developed that describes convection, dispersion, kinetic reactions of carbonate dissolution and chromium precipitation, and chemical equilibrium for reactions between aqueous components. Experimental data and data taken from literature were simulated by the model.
Rate-Time Flow Behavior of Heavy Oil From Horizontal and Multilateral Wells
Authors: Fetkovich M. D. , Petrosky G. E. , Hughesman C. B. , Sawatzky R. P. 
Published: December 2007

Abstract
This paper examines the behavior of heavy oil reservoirs developed with horizontal and multilateral wells. Advanced decline curve analyses were used to characterize flow regimes and estimate the time to pseudosteady-state. Reservoir and well parameters such as the OOIP, Arps "b" exponent, decline rate, reserves, permeability and well productivity indices were also determined.
Example analyses are presented for single, dual and triple lateral wells from heavy oil fields located in Venezuela and Canada. All wells exhibit a characteristic extended transient linear flow regime followed by an exponential decline. Similar results were obtained whether the analyses were performed on single, dual or triple lateral wells. Interference between laterals was not observed.
Simulation of Gelled Polymer Treatments in the Arbuckle Formation, Kansas
Authors: Barati R. , Green D. W. , Liang J. T. 
Published: December 2007

Abstract
Gel polymer treatments have been carried out on a large number of producing wells in the Arbuckle Formation of Central Kansas. These treatments have been aimed both at reducing water coning from an underlying aquifer and increasing oil production. This paper describes computer simulation of two of these gel-treated wells. One is a well for which the treatment was successful and the second is a well which responded far less favorably. For each well, performance before, during and after a treatment was modeled using single porosity and dual permeability models, i.e. reservoir simulators that are based on matrix flow only or on fracture-matrix flow. For the fracture-based model, it was assumed that the producing well was connected to an underlying aquifer through a high vertical permeability fracture system.
Well performance during the polymer injection period of the treatments and the post-treatment behavior were such that there were major differences in history matching between the single porosity model (no fractures) and the fracture model. For the well that was treated successfully, behavior during polymer injection as well as post-treatment performance could be matched only with the dual permeability model. No reasonable set of parameters was identified for the single porosity (matrix flow) model that allowed a suitable history match of these same data. For the well that was treated unsuccessfully, the converse was true. An acceptable history match was obtained only with the single porosity model or with the fracture model with a very sparse fracture density. The results indicate that the presence of natural fractures connected to an aquifer is an important feature of the Arbuckle wells that respond favorably to polymer gel treatments.
Modeling Wettability Alteration in Naturally Fractured Reservoirs
Authors: Delshad M. , Najafabadi N. F. , Anderson G. A. , Pope G. A. , Sepehrnoori K. 
Published: December 2007

Abstract
Laboratory surfactant and hot water floods have shown a great potential in increasing oil recovery for reservoirs that are naturally fractured and have low permeability mixed-wet matrix rocks. Fractured, mixed-wet formations usually have poor waterflood performance because the injected water tends to flow in the fractures and spontaneous imbibition into the matrix is not very significant. Surfactants have been used to change the wettability for increasing the oil recovery by increased imbibition of the water into the matrix rock. The mechanisms for oil recovery are combined effects of reduced interfacial tension, reduced mobility ratio, and wettability alteration. The goal of this research is to adapt an existing numerical reservoir simulator to model chemical processes that lead to wettability alteration in naturally fractured reservoirs. Surfactants have been used to change the wettability with the goal of increasing the oil recovery by increased imbibition of the water into the matrix rocks. Reservoir simulation is required to scale up the process from laboratory to field conditions and to understand and interpret reservoir data. We have adapted the chemical flooding simulator, UTCHEM, to model improved oil recovery processes that involve wettability alteration using surfactants. Multiple relative permeability and capillary pressure curves corresponding to different wetting states are used to model the wettability alteration. Simulations were performed to better understand and predict enhanced oil recovery as a function of wettability alteration and to investigate the impact of uncertainties in the fracture and matrix properties, reservoir heterogeneity, matrix diffusion, buoyancy driven flow, initial water saturation, and formation wettability.
Optimization of Chemical Flooding in a Mixed-Wet Dolomite Reservoir
Authors: Anderson G. A. , Delshad M. , King C. B. , Mohammadi H. , Pope G. A. 
Published: December 2007

Abstract
Many pilot tests and several commercial field projects have been performed over the past few decades and have shown that surfactant/polymer and alkaline/surfactant/polymer floods can recovery high percentages of residual oil saturation. However, these chemical processes are sensitive to parameters such as chemical slug size and concentrations, salinity, reservoir heterogeniety and surfactant adsorption among other key parameters. In this study, a sensitivity analysis of these key parameters was performed to optimize a chemical flood design for a mixed-wet dolomite reservoir in the Permian Basin. The simulations were performed using the reservoir simulator UTCHEM, a multiphase, multicomponent chemical flooding simulator. The base case design was developed using a reservoir model provided by the operator, injection and production rate constraints from actual field conditions, brine and oil properties from the field, and chemical properties provided by the EOR laboratory at the University of Texas. An optimum design was selected based on net present value calculated from discounted cash flow analysis. The results of this study showed that chemical flooding this mixed-wet dolomite reservoir is likely to be profitable over at range of crude oil prices based upon the laboratory performance of the surfactant/polymer flood and the optimum process design determined in this study.
Scratch Testing of Drilling Mud Filter Cakes
Authors: Cerasi P. , Larsen I. , Stenebråten J. F. , Sønstebø E. F. 
Published: December 2007

Abstract
We adapted a scratch apparatus used to evaluate shear strength and stiffness of rocks to use on soft filter cakes, to obtain quantitative information on cake properties for modelling purposes. The modelling will help design better drilling fluids, in terms of their filter cake's resistance to oil production onset. Scratch testing of rock specimens is now a well established method to obtain reliable strength and stiffness measurements as a function of distance along the scratched surface. The apparatus consists of a rigid frame holding a cutter, being pushed at a constant velocity over a rock specimen. A micrometric screw allows the user to choose a precise cutting depth, while a bidirectional load cell monitors the shear and normal forces on the cutter. The shear force can be related to the specific energy of cutting, which in turn correlates with the Unconfined Compressive Strength (UCS) of the rock. New low-resolution load cells have been installed in anticipation of the orders of magnitude lower expected values when scraping filter cakes. Rocks were exposed to different fluids to assess the impact on filter cake quality and inner filter cake properties. The effect of the internal filter cake on the rock was also addressed by scratching the rocks prior to filtration and once again after, scratching through the filter cake, on the exposed rock face. Quantitative and detailed probing of filter cake elastic properties is now possible using the scratch method. Concerns about removing the filter cake all at once (especially when OBM systems are tested, known for their low adhesion) turned out to be unfounded; the tool was capable of scraping out clean, well-defined cake layers, down to a thickness of 0.1 mm.
Application of Artificial Intelligence in Gas Storage Management
Authors: Zangl G. , Giovannoli M. , Stundner M. 
Published: December 2007

Abstract
An approach is investigated, to reduce the amount of CPU time needed to execute a numerical full field model in an optimization loop.
To demonstrate the power of this approach, a real life example is presented. Data from a gas storage reservoir have been used to setup a single tank material balance program. Then, a limited number of simulation runs is carried out. These simulation runs are intended to span over the whole range of input parameter variation (app. 25 runs).
In a next step, a Neural Network (NN) model is setup. By training a Neural Network on the so gained simulation outputs, a model, which is able to interpolate between the individual simulation scenarios is created. In this way, a large variety of different scenarios can be represented with a limited amount of model runs.
The trained Neural Network model is used as a proxy function for an optimization routine. The trained Neural Network has been used as fitness function for the Genetic Algorithm to minimize the output parameter, which is in this example the RMS-error of measured and calculated tank pressure. Due to the very low CPU consumption of the Neural Network, a large number of realisations can be calculated in a short amount of time. By this, the absolute minimum of the desired output parameter (in this case the RMS-error) can be evaluated in a few seconds.
The Genetic Algorithm has succeeded to find a minimum, which is located very close to the absolute minimum of all possible solutions.
Use of Ensemble Kalman Filter With 3-Dimensional Reservoir Characterization During Waterflooding
Authors: Park K. , Choe J. 
Published: December 2007

AbstractIn order to estimate reserves accurately and maximize oil and gas productions, it is critical to characterize unknown properties of a reservoir. However, it is very challenging because of severe non-linearity, non-uniqueness, and large number of variables with different levels of uncertainties. In 1994, the Ensemble Kalman Filter (EnKF) was developed in ocean dynamics. Afterwards, EnKF has been successfully applied in many areas such as oceanography, hydrology, and navigation systems to overcome those difficulties in non-linear inverse modeling.Recently, EnKF was introduced to petroleum engineering for continuous reservoir update. Although its applications look promising, there are couples of complicated problems observed for updating a reservoir model. Firstly, although there are more available measurements, the tendency to find the solution may not look satisfactory after some number of updates, especially near the boundaries. Secondly, because EnKF is based on mathematical theories, the solution sometimes includes physically unreasonable values. Therefore, we need to improve EnKF for successful reservoir characterization.In this paper, we investigate causes of the two problems mentioned and find methods that are able to resolve them. For our objectives, we develop a reservoir characterization model using EnKF and apply to waterflooding using streamline approach for multiphase reservoir simulation. After certain number of updating, estimate error covariance of the ensemble reduces to very low, and the ensemble members become close and do not provide any ensemble effects. In order to solve the problem, we control the decrease of estimate error covariance through the regeneration of ensemble, which results in increase of error covariance.Additionally, we examine the measurements thoroughly and use the measurement data selectively which contain helpful data for model updates. For example, the saturation data before and after the breakthrough are not sensitive to reservoir permeability or porosity distribution. However, the unnecessary measurements can make significant undesirable updates in EnKF. In a synthetic reservoir, the developed EnKF relieves the effects of the two problems and provides satisfactory solution for real-time history matching and reservoir characterization with high efficiency and reliability.
New Ways of Handling and Running C.R.A. Tubulars Prevent Corrosion in H2S and CO2 Environments
Authors: Kinzel H. , Kiess C. , Wachs T. P. , Badrak R. P. 
Published: December 2007

Abstract
In a corrosive downhole environment, the service life of a completion can be severely reduced if no precautions against corrosion are taken. Pipe made of corrosion resistant alloys (C.R.A.) is used to minimize corrosion. An analysis of various corrosion mechanisms shows that the surface integrity is an important factor for corrosion prevention [3].
Conventional spider and elevator inserts as well as conventional hydraulic power tong dies made of steel cause die marks that support corrosion. A gripping system named Micro-Grip distributes the required load equally onto a large number of small peaks, minimizing the indentation of each single peak [1-3]. This system is available for power tongs as well as accessories such as safety clamps.
In corrosive downhole environments, such as those that contain relevant quantities of CO2 and/or H2S at elevated temperature, C.R.A. materials with a high chromium content are often selected for the tubular and related accessories. In these environments using C.R.A., companies developed a "zero marking" policy especially for the makeup of the connections. In connection with higher torque values, this required a new gripping technology. A so-called Diamond-Grip gripping system was developed, together with a hydraulic gripping system for the power tong that delivers the required radial forces.
The paper describes this new gripping technology and a series of tests that were performed within pre-qualification processes for C.R.A. handling and running tenders in Qatar as well as in the Gulf of Mexico. The tests showed that there is no negative impact of Diamond-Grip and Micro-Grip in regards to corrosion under the severe influence of H2S and CO2.
The Relative Importance of Wellbore Pressure Drop and Formation Damage in Horizontal Wells
Authors: Hill A. D. , Zhu D. 
Published: December 2007

AbstractNumerous studies have examined the roles of wellbore pressure drop and near wellbore formation damage on the production performance of horizontal wells. These studies have identified particular conditions for which these effects are important, but no quantitative general guidelines have been developed. In this paper, we present simple, analytical expressions that can be used to determine the relative effects of wellbore pressure drop and formation damage on horizontal well inflow. The equations developed are used to show how horizontal wells or laterals can be designed so that neither of these effects causes significant flow restrictions.The relative importance of the pressure drop in a horizontal wellbore is shown to be a simple function of two dimensionless numbers, the Reynold's Number for the flow in the wellbore, and a new dimensionless number called the Horizontal Well Number. With this relationship, we illustrate how the wellbore diameter and length can be designed to insure that the wellbore pressure drop is not restricting production.We also illustrate in this paper a technique for identifying the most critical part of the well flow system (far-field reservoir flow, near well convergent flow, or flow through the completion) from the relative sizes of different terms in the inflow equations. This analysis method shows that the importance of formation damage and the efficiency of well stimulation depend on formation thickness, well length, and reservoir extent in the horizontal plane. Guidelines are presented to show how much damage can be tolerated while still maintaining productivity within a prescribed fraction of the undamaged productivity.
Detection of Water or Gas Entries in Horizontal Wells From Temperature Profiles
Authors: Yoshioka K. , Zhu D. , Hill A. D. , Dawkrajai P. , Lake L. W. 
Published: December 2007

Abstract
With the recent development of temperature measurement systems such as fiber optic distributed temperature sensors (DTS), continuous temperature profiles in a horizontal well can be obtained with high precision. Small temperature changes with a resolution on the order of 0.1 °F can be detected by modern temperature-measuring instruments in intelligent completions and may aid the diagnosis of downhole flow conditions. Since in a producing horizontal well, fluid inflowing temperature is not affected by elevational geothermal temperature changes, the primary temperature differences for each phase (oil, water, and gas) are caused by frictional effects.
While gas production usually causes a temperature decrease, water entry results in either warming or cooling of the wellbore. Warmer water entry is a result of water flow from a warmer aquifer below the producing zone (water coning). In contrast, produced water can be cooler than produced oil because of differences in the thermal properties of these fluids. If both oil and water are produced from the same elevation, oil is heated more by friction while flowing in a porous medium than water, resulting in the produced water having a lower inflow temperature than the oil. Water entry by coning is relatively easy to detect from the temperature profile because of its warmer inflow temperature, but water breakthrough from the same elevation as the oil may not be obvious.
In this paper, we illustrate the range of inflow conditions for which water or gas entry locations can be identified from the temperature profile of a well from measurable temperature changes. Using a temperature prediction model1, we calculated temperature profiles for a wide range of water inflow conditions. In these calculations we assumed that one section of the well was producing water or gas, while the rest of the open section of the well produced oil. From sensitivity studies, we identified the relative water and gas production rates that create detectable temperature anomalies in the temperature profile along the well.