bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulation, Design and Management of Waterflooding Projects in Mature Multi-Storey Fields in the Golfo San Jorge Basin - Argentina
Authors: Palacios Gustavo Rogelio , Paradiso Antonio Alfredo , Tuero Fernando 
Published: July 2010

Abstract
The Golfo San Jorge Basin in Argentina presents a great challenge to Reservoir Engineers due to its complex reservoir conformance and scarcity and poor quality of petrophysical and fluid data, making the use of conventional numerical simulators non-pragmatic.
This paper presents a simple and effective methodology that through the integration and validation of all the available data, coupled with an ad-hoc developed software tool, permits the construction of an analytical simulation model to design, monitor and forecast future production of waterflood (WF) projects in this type of multi-storey and mature fields.
Additionally, a summary is presented showing interesting results from a large number of studies with the application of the aforementioned methodology during more than 10 years of experience in WF projects assessment.
An Integrated Method for Well Deliverability Forecasting: A Field Example In ShengLi Oilfield
Authors: Yun Xie , Bin Xin Zhong , Sheng Zhou Jia , Jin Wang , Jun Zhang , Khong Chee Kin , Jing Zhou , Qiang Niu Yu , Li Chen 
Published: July 2010

Abstract
Well deliverability is a critical reservoir parameter that defines well performance. Accurate knowledge of deliverability is very important for reserve booking and production facility design. Reliable well deliverability can be obtained from DST (Drill Stem Test) on selective perforation of individual layers and/or straddle tests for commingled producers. However, these methods are both time and cost consuming. Simple single well analytical model can be built to calculate well deliverability. But it often does not count for certain factors such as: formation heterogeneity & anisotropy, initial oil saturation, reservoir with bottom or edge-drive aquifers, as well as capillary force and relative permeability. Therefore the result can be unreliable. Under this situation, numerical model is the solution.
This paper presents a method to forecast well deliverability with a comprehensive approach to factor in various reservoir parameters. A single well numerical model is developed by integrating Nuclear Magnetic Resonance (NMR), borehole image, open-hole logs, well test and/or formation tester, and core data together. The workflow of the method includes four steps: 1) perform petrophysical interpretation and lithofacies characterization and hydraulic flow unit (HFU) classification, 2) calibrate NMR derived permeability, capillary and relative permeability curves with special core analysis, 3) construct a dynamic model and calibrate it with well testing and/or/ formation testing data, and 4) forecast well deliverability with the calibrate numerical model under different completion and well management options.
A case study is presented to illustrate this integrated approach. The single well model was calibrated with well test data for a tested zone, then the calibrated model was used to forecast well deliverability for the rest zones where no well tests were performed. Subsequently sensitivity analysis was performed on formation damage. Also bottom/edge water drive effect on well deliverability were analyzed. This case study shows that the well deliverability forecasted with this workflow has greatly reduced the uncertainty and enhanced the understanding of the reservoir performance for decision making.
Improved Heavy Oil Recovery by CO2 Injection Augmented with Chemicals
Authors: Zhang Y. P. , Luo P. , Huang S. 
Published: July 2010

Abstract
During water-alternating-gas (WAG) flooding for heavy oil reservoirs, the adverse mobility ratio leads to a considerable amount of injection gas fingering through and overriding the oil zone. To improve the recovery efficiency of the WAG process in a Saskatchewan (Canada) heavy oil reservoir, the Saskatchewan Research Council (SRC) conducted a laboratory feasibility study of augmenting the injection water with chemicals (alkaline/surfactant/polymer). The resulting process is known as CAG, or chemical-alternating-gas (CO2 or flue gas). SRC's integrated approach included interfacial tension (IFT) and rheology measurements, phase behaviour studies, micromodel displacements, and corefloods to evaluate the effectiveness of the CAG process. The results showed that addition of ASP into the injection water could significantly lower IFT (to 10−2 mN/m) and improve mobility. The phase behaviour studies indicated that CO2 could be dissolved readily into reservoir heavy oil at moderate pressures (3.4–6.4 MPa), resulting in dramatic oil expansion (1.2–8.1%) and viscosity reduction (45–88%). It was also demonstrated that the presence of 70% N2 in the CO2 stream (i.e., flue gas) greatly reduced the gas solubility, causing negligible oil swelling and viscosity reduction at the reservoir pressure. It was observed from micromodel displacement tests that CO2 viscous fingering and breakthrough occurred quickly even at a low pressure of 2.3 MPa, indicating the need to lower the capillary pressure between the heavy oil and porous media and add a mobility buffer between the CO2 and heavy oil. The coreflood results showed that a conventional CO2-WAG process recovered more incremental oil than a flue gas-WAG (9.43 vs. 3.58% OOIP), whereas a CO2-CAG and a flue gas-CAG recovered incremental oil of 27.43 and 22.07% OOIP, respectively. The comprehensive studies suggest that the CO2-CAG process holds promise for recovering Saskatchewan's tremendous heavy oil resources.
Using Downhole Temperature Measurement to Assist Reservoir Characterization and Optimization
Authors: Li Zhuoyi , Yin Jichao , Zhu Ding , Datta-Gupta Akhil 
Published: July 2010

Abstract
Downhole temperature distribution in horizontal wells can be an important source of information that helps us characterize the reservoir and understand the bottom-hole flow conditions. The temperature measurements are obtained from permanent monitoring systems such as downhole temperature gauges and fiber optic sensors. Also, production history and bottomhole pressures are usually readily available and are routinely used for history matching to improve the initial geological models. Combining the downhole temperature distribution and the production history, we can extract more reliable information about the reservoir permeability distribution and bottomhole flow conditions that help us optimize the wellbore performance, particularly in horizontal wells.
In this paper, we use a thermal model and a transient, 3D, multiphase flow reservoir model to calculate the wellbore temperature distribution in horizontal wells. By comparing the simulated temperature and the observed data, we first derive large-scale permeability trends in the reservoir. These permeability trends are then incorporated as ‘secondary’ information in the geologic model building and history matching. Finally, the updated permeability models from history matching are used to infer the downhole flow conditions along horizontal wells. The final outcome is a geologic model that is consistent with reservoir static and dynamic information, and also the wellbore temperature measurements.
We present several synthetic cases to illustrate the procedure. The results show that with only production history matching without distributed data along the wellbore, the water entry location in horizontal wells can not be detected satisfactorily. Combining production history matching with the temperature distribution in the wellbore, we can get an improved geological model that can match the production history and also, locate the water entry correctly. Based on the downhole flow conditions and the updated geological model, we can now optimize the well performance by controlling the inflow rate distribution, such as shutting the high water inflow sections.
Fracture Permeability of Gas Shale: Effects of Roughness, Fracture Offset, Proppant, and Effective Stress
Authors: Kassis Sarah , Sondergeld Carl H. 
Published: July 2010

Abstract
Domestic gas shale production is made economic through new completion practices which include horizontal wells and multiple hydraulic fractures. The performance of these fractures is improved through the injection of proppant. Success has largely been based on empiricism through field experiments. We attempt to remove some uncertainty in this empiricism through a series of laboratory controlled experiments. We have measured the permeability of fractured rock as a function of effective stress, proppant, proppant distribution and fracture offset. Our findings indicate that fracture offset is as effective as propping a fracture; both increase initial permeabilities more than 1000 fold over initial fracture values. However, the pressure dependence of the propped fracture is stronger, i.e. the permeability is reduced more per increment of pressure than the offset fractures. Neither obeys the simple cubic pressure dependence law proposed by Walsh. A simple monolayer of proppant is as effective as a fairway distribution of proppant in enhancing permeability. Initial fracture permeability is dependent on surface roughness, quantified as root mean square asperity heights. Pressure dependence of permeability of these fractured surfaces does obey the Walsh permeability models. SEM observations of surfaces and proppant suggest a new approach to proppant design.
Hole Cleaning Performance of Gasified Drilling Fluids in Horizontal Well Sections
Authors: Ozbayoglu M. E. , Osgouei R. E. , Ozbayoglu A. M. , Yuksel E. 
Published: July 2010

Abstract
This study aims to investigate the hole cleaning process during the flow of a drilling fluid consist of a gas and a liquid phase through a horizontal annulus. Experiments have been conducted using METU Multiphase Flow Loop under a wide range of air and water flow rates while introducing cuttings into the annulus with several different amounts. Data has been collected for steady state conditions, i.e., liquid, gas and cuttings injection rates are stabilized. Collected data include flow rates of liquid and gas phases, frictional pressure drop inside the test section, local pressures at different locations in the flow loop, and high-speed digital images for identification of solid, liquid and gas distribution inside the wellbore. Digital image processing techniques are applied on the recorded images not only for volumetric phase distribution inside the test section, but also examination of the transport velocities of cuttings particles, which are in dynamic condition. The effects of liquid and gas phases are investigated on cuttings transport behavior under different flow conditions. Observations showed that the major contribution for carrying the cuttings along the wellbore is the liquid phase. However, as the gas flow rate is increased, the flow area left for the liquid phase drastically decreases, which leads to an increase in the local velocity of liquid phase causing the cuttings to be dragged and moved, or a significant erosion on the cuttings bed. Therefore, increase in the flow rate of gas phase causes an improvement in the cuttings transport although the liquid phase flow rate is kept constant. Based on the observations, a mechanistic model which estimates the total cuttings concentration inside the wellbore and developed frictional pressure loss is introduced for gasified fluids flowing through horizontal annulus. The model estimations are in good agreement with the measurements obtained from the experiments. Using the model, minimum liquid and gas flow rates are identified for having an acceptable cuttings concentration inside the wellbore as well as a preferably low frictional pressure drop. Thus, the information obtained from this study is applicable to any underbalanced drilling operation conducted with gas-liquid mixtures, for optimization of flow rates for liquid and gas phases in order to transport the cuttings in the horizontal sections in an effective way with a reasonably low frictional pressure loss.
Comparison of Completion and Heterogeneity Effect on CO2 Sequestration in Shallow and Deep Saline Aquifers
Authors: Yang Fang , Bai Baojun , Tang Dazhen , Dunn-Norman Shari , Wronkiewicz David 
Published: July 2010

AbstractThe effect of completion techniques and reservoir heterogeneity on CO2 storage and injectivity in saline aquifers has been studied using a compositional reservoir simulator CMG-GEM. Two reservoir models were built using data extracted from publications, to represent a deep saline aquifer and a shallow aquifer. The effect of completion methods, including partial perforation of the reservoir net pay (partial completion), well geometry, orientation, location and length, on CO2 storage are discussed. Heterogeneity effect has been addressed considering three parameters: mean permeability, vertical to horizontal permeability ratio, and permeability variation. Sensitivity analysis was carried out using design of experiments (DOE) to determine the dominant factors affecting CO2 storage capacity and CO2 injectivity. Simulation results show that completing all layers, using horizontal wells set in upper layers with a length around 250–300 m are the most favorable choices for CO2 storage capacity in the aquifer examined. Mean permeability affects CO2 storage capacity and injectivity the most; kv/kh affects CO2 injectivity storage capacity more than permeability variation, Vk. More CO2 can be stored in the heterogeneous reservoirs with low mean permeability; however, high injectivity can be achieved in the uniform reservoirs with high mean permeability.
CO2 Sequestration in a Depleted Gas Field: A Material Balance Study
Authors: Stein M. H. , Ghotekar A. L. , Avasthi S. M. 
Published: July 2010

Abstract
The material balance techniques have been used in the oil and gas industry for estimating hydrocarbon reserves for a long time. The objective of this paper is to introduce a fairly simple and fast material balance technique that can provide a fairly good estimate of CO2 storage capacity in depleted gas reservoirs.
Sequestration of CO2 in geological formations is a strategy currently being considered for decreasing CO2 emissions to the atmosphere. These geological formations can be either depleted oil and gas reservoirs or saline reservoirs. A depleted gas reservoir can store significantly more gas than a depleted oil reservoir due to the fact that gas is more compressible than oil and the ultimate recovery in gas reservoirs is higher than that in oil reservoirs. Many researchers have published reservoir simulation studies of CO2 sequestration in depleted gas fields, however, a reservoir simulation study, depending on its complexity, can take several months to perform. In this paper, a fairly simple and fast material balance technique, combined with nodal analysis, is presented that can provide a fairly good estimate of CO2 storage capacity in depleted gas reservoirs.
A depleted gas reservoir, for which the production and pressure history data were available, was selected as a candidate to perform this material balance study. First the material balance calculations were performed to estimate the size of the gas reservoir, aquifer and reservoir pressure. The formation parting pressure was estimated based on basic rock mechanics principles as a function of reservoir pressure. The bottom hole injection pressure was maintained below the formation parting pressure, until the surface facilities limitations were reached. As a result of this study, the amount of CO2 that can be stored in this depleted gas reservoir was estimated within a few weeks.
Calculation of Oil and Water Relative Permeability for Extra Low Permeability Reservoir
Authors: Liu Renjing , Liu Huiqing , Li Xiusheng , Wang Jing , Pang Changting 
Published: July 2010

Abstract
As an important parameter of multiphase flow in porous media, relative permeability curve is often calculated by JBN method which ignores the capillary pressure. However, owing to the fine throat and the complex construct in extra low permeability reservoir, the capillary pressure is very significant. In addition, researches have shown that the flow in low permeability media doesn't follow the Darcy's law and there is threshold pressure gradient occurring in the percolation. Therefore, the traditional method is no longer available for the extra low permeability reservoirs and a new method is needed urgently to resolve this problem.
In this paper, the relative permeability of extra-low permeability core was calculated by three methods: JBN method, fractal model and modified JBN method. The fractal model was set up based on the capillary pressure curve and the fractal geometry theory. The modified JBN method taken into the effects of capillary pressure and threshold pressure gradient, and a semi-log fit function other than polynomial function was used to improve the accuracy.
The results show that, comparing with JBN method, the fractal model and the modified JBN method can predict the relative permeability more accurately. And the modified JBN method is the best. The water cut calculated by the new method matched the production data better than that calculated by JBN method.
The new method overcomes the limitations of previous researches. It can be used to calculate relative permeability for extra low permeability reservoirs more accurately and help to develop extra low permeability reservoirs more reasonably.
Research on the Formation Pressure Prediction in the Exploration Area of Northeast Sichuan, China
Authors: Jie Cui , Sun Mingxin , Li Zhonghui 
Published: July 2010

Abstract
The geologic condition in the northeast of Sichuan is so complex that many drilling complexities like leakage, kicking, collapse and sticking often occur. There are many types of gas reservoirs such as pore, interstice, pore-interstice, interstice-pore space and so on. A multiple of pressure system and an ultrahigh pressure gas reservoir exits which contain hydrogen sulfide gas in the carbonate formation. Research on the formation pressure calculation is carried out and a pressure model is established in order to ensure the safety drilling. The priority is to study the pressure in marine formation based on the characteristic of formation pressure which has high sensibility on ratio between P-wave and T-wave's speed in carbonate rock formation. The formation pressure profile is built by the pressure model and well logging date. There is little error in the results so that they can meet the project demands. The results is very important in exploring gas in northeast of Sichuan.
Study on Operating Parameters of CO2 Supercritical Pipelines
Authors: Li Changjun , Wu Xia , Jia Wenlong , Liu Enbin , Liao Kexi 
Published: July 2010

Abstract
Supercritical pipelines are most commonly used in CO2 transportation. Liquid models are always utilized for design and hydraulic checking of those pipelines. However, supercritical CO2 may show significant characteristics of gaseous under certain operating condition. This phenomenon may increase pressure drop so that pressure values will be different from calculation results from liquid models. According to comparing the compression factor and density curve of liquid and supercritical CO2, the fact that when operation parameters of supercritical pipelines occupy in certain pressure and temperature regions, compressibility of CO2 cannot be neglectd is concluded. On the basis of density variation tendency, the method and its steps which are used to delimit compressible region of supercritical CO2 are proposed. Compared with this compressible region, operating parameters of supercritical pipelines can be checked. The application example calculates the pressure drop both by liquid model and gaseous model which considers copressibility. The results verified that delimited method of compressible region is accurate and reasonable.
Profile Controlling by Horizontal Well Completion Strings with Inner-located Nozzle
Authors: Li Liangchuan , Liu Huiqing , Zhang Hongling , Wang Qing 
Published: July 2010

Abstract
Horizontal well has been used successfully in small block and offshore reservoirs and reservoirs with bottom water for cresting control. Watering-out profile along horizontal well in the reservoir with bottom water can be identified by production logging or by production history matching. The logging information shows that the profile is related to the formation permeability distribution in the well, and the flowing disturbance between high and low permeability interval has been tested from room experiment in a square sand pack model with vertical heterogeneity, it has been shown that start-flowing for displacing fluid though low permeable part in heterogeneous formation depends mainly on the permeability ratio of high to low. The ratio limit is about 3 for light oil reservoir, and little fluids will flow in low permeable part of the perforation interval for commingled injection or producing well. Well completion strings has been designed with concentric tube, filtering cotton coated for outer slotted wall and nozzle located in the inner wall. There may be empty between formation sandface and the well completion strings, and gravel packing and/or packer can be used. Variable mass flow dynamic models have been built based on momentum balance for two channels, and fluids flow transfer between the neighbor channels has been included, flowing relation with watering-out profile character and fluid flowing though gravel packing and/or packer barrier will be coupled in the model. Finite difference scheme has been used to solving the equations and coding procedures, pressure and flow rate distribution in the two channels can be calculated, flowing rate and pressure distribution are not symmetry because of interference of fluids transfer between channels. Different nozzle size and location can be determined for the watering-out profile changing, outer gravel packing and packer spacing can be designed also. The method has been used in the designing for well completion strings in Jidong oil field, and production performance of the well has been shown that the completion strings with inner-located nozzle in horizontal well is successful.
A New Deliverability Testing Method for Gas Condensate Wells
Authors: Shi Juntai , Li Xiangfang , Shi Depei , Xu Hanbing , Li Baozhen , Zhou Jianrui 
Published: July 2010

Abstract
In the process of well testing on gas condensate well, if the condensate liquid retrogrades from gas phase, which will adhere to the surface of the rock, the key reservoir parameters would vary, such as the permeability and the skin factor. The changes of reservoir parameters could affect the deliverability of a gas condensate well, by changing the coefficients of A and B in the deliverability equation. These changes make it inapplicable to use the deliverability equation for a conventional gas well to interpret the deliverability of a gas condensate well.
In view of the problem above in the process of well testing on gas condensate well, the model in this paper was built up in view of different pressure region, and could reflect the deliverability equation under the specific testing condition, so it could interpret the deliverability of a gas condensate well under different production stages. A new method to model and construct a deliverability equation with variable coefficients or many independent deliverability equations, which can represent the performance of well, was put forward in this paper.
Through applying the deliverability test method put forward in this study to a case, results obtained from this method keep consistent with the real testing data, so the deliverability of a gas condensate well obtained by using this method in different process of production can be correctly evaluated.
The created deliverability equation could reflect not only the characteristics of gas reservoir testing and dynamic performance, but also four-dimensional changes of rock properties and flowing parameters of reservoir fluid, so the well performance in the future could be more accurately predicted.