bluuebunny/crossref_metadata_2025_split huggingface dataset:
Research and Application of Mathematical Model for Foam Diversion Acidizing
Authors: Li Songyan , Li Zhaomin , Lin Riyi , Li Binfei 
Published: March 2008

Abstract
Foam diversion can effectively solve the problem that acid distribution among layers of different permeability is uneven during matrix acidizing. Based on gas trapping theory and mass conservation equation, mathematical models for foam slug diversion acidizing and foamed acid diversion acidizing were established. Design method for foam slug diversion acidizing was given. The mathematical models were solved by computer program. The results show that total formation skin factor, and pressure of wellhead and bottomhole increase with foam injection, and decrease with acid injection. Volume flow rate of high-permeability layer decreases, and that of low- permeability layer increases during foam injection, which can divert subsequent acid to low-permeability layer from high-permeability layer. Under the same formation situation, the effect of foamed acid diversion acidizing is better than foam slug diversion acidizing. In foamed acid diversion acidizing process, operation time is longer, and pressure of wellhead and bottomhole is higher. Field application shows that foam slug diversion acidizing can effectively block high permeability layer, and improve intake profile obviously. It is fit to acidizing for heterogenous formation.
Direct Current Electrical Enhanced Oil Recovery in Heavy-Oil Reservoirs To Improve Recovery, Reduce Water Cut, and Reduce H2S Production While Increasing API Gravity
Authors: Wittle J. K. , Hill D. G. , Chilingar G. V. 
Published: March 2008

Abstract
Electro-Petroleum, Inc. (EPI) has successfully demonstrated use of DC electrical current for enhanced oil recovery (a process we now call "Electro-Enhanced Oil Recovery", or EEOR) at heavy oil fields in the Santa Maria (California) Basin and the Eastern Alberta Plains. They have also conducted large-scale (1 cu-m sample size) laboratory studies to evaluate unexpected results from these field demonstrations.
Dr. G. V. Chilingar, of the University of Southern California, publicly advocated using a similar technology in the 1960’s. Several successful applications of similar technology have been claimed, in the Former Soviet Union.
Field studies in California have demonstrated up to a ten-fold increase in oil production from a field containing 8° API gravity oil. Recent research has demonstrated that the EEOR process is also capable of cold cracking of heavy oil in-situ, resulting in lighter produced oil and increased reservoir pressures. EEOR can function at depths below 10,000 feet, well below the 2,500 ft. practical limit for steam flood operations. Observed changes in the produced fluids include:Increased oil production rates.Reduced produced oil viscosity increased API gravity).Reduced water cut.Reduced H2S production.Increased gas production.Increased produced gas energy (heavy gas) content.Reduced PAH production.
All of these observed fluid chemistry changes can be explained by the use of DC electrical technology.
A Quadratic Cumulative Production Model for the Material Balance of an Abnormally Pressured Gas Reservoir
Authors: Gonzalez F. E. , Ilk D. , Blasingame T. A. 
Published: March 2008

Abstract
The premise of this work is the concept, development, and application of an approximate relation for the material balance of abnormally pressured gas reservoirs. In particular, the proposed approximation is formulated directly from the rigorous material balance for the case of an abnormally pressured gas reservoir. Our "quadratic cumulative production" result is given by: (1)pz≈pizi[1−[1G−ω]Gp−ωGGp2]
where ω is defined as a function ofGp
The ω-function is defined by the "cumulative effective compressibility" [ c¯e (p)] and represents the influence of abnormal pressure. If we assume ω =constant (but this does not mean that c¯e (p) is constant), then we obtain the "quadratic" formml: (2)pz≈pizi−αGp−βGp2whereα=1G−ωandβ=ωG
Eq. 2 is the base definition of the "quadratic cumulative production" relation (ω is constant; therefore, α and β are constant). We have shown this relation to be an extraordinarily accurate approximation of the rigorous material balance for the case of a dry gas reservoir with abnormal pressure effects.
Eq. 2 is suited not only for use as a characteristic model, but also for use as a data analysis mechanism (i.e., in this work we use Eq. 2 to develop a suite of analysis plots, plotting functions, a type curve, etc.). We also address the case of ω being a linear function of Gp (as opposed to ω being constant) — which results in a formulation where p/z is cubic in terms of Gp.
In this work, we provide the following new results: The "quadratic cumulative production" model for the material balance behavior of abnormally pressured gas reservoir.A suite of 6 (six) plotting functions based on the p/z-G2 material balance model.A suite of 4 (four) ω-Gp performance plots which are used to calibrate the analysis process.A new type curve pD[=(pi/zi-p/z)/pi/zi] versus GpD[=Gp/G], based on the new p/z-G2 material balance model.

Objectives
The primary objectives of this work are:
Optimized Foam Drilling Improves Drilling Performance in Iranian Carbonate Fields
Authors: Shirkavand F. , Hareland G. , Teichrob R. , Haeri Behbahani S. M. 
Published: March 2008

Abstract
The advantages of foam drilling over conventional mud drilling have long been recognized and include faster penetration rates, longer bit life, prevention of lost circulation and less formation damage to the producing reservoir resulting in overall drilling cost reduction and higher production rates. Careful practical design and control of gas and liquid volumes, injection pressure and annular backpressure must be applied in foam drilling to achieve the optimum results. Optimization of foam drilling is done by drilling with the lowest acceptable bottom hole pressure and making sure that the wellbore is kept clean. This is done by applying an integrated flow model that accounts for both the compressibility of the foam, the hydrostatic column and the frictional pressure losses in conjunction with minimum hole cleaning requirements. The model is integrated with the hole cleaning requirements to obtain the balanced and lowest bottom hole pressure for the operation. The equations, procedure and sample application of this method are presented herein. Using this UBD approach on Iranian oil fields indicates large cost savings. The drilling operations in the Shanoul and Parsi fields shows as much as 60-70 percent reduction in bottom drilling time using foam drilling compared to conventional mud drilling. Using the optimum volumetric model for foam drilling and a series of simplified hole cleaning charts presented herein, the foam drilling program for the Shanoul field enabled determination of optimum drilling and hole cleaning parameters in this field. This paper presents results from programming of near balanced conditions using a new foam drilling program designed for the Shanoul field. The target formations were hard, fractured and depleted limestone formations with low pressure. The paper also compares the results to similar wells drilled with aerated fluids and conventional muds, which indicates the foam drilling as being superior in terms of rate of penetration longer bit life and less wellbore instability. A drilling cost study comparing conventional, aerated and foam drilling is also presented.
The Effect of Geologic Parameters and Uncertainties on Subsurface Flow: Deepwater Depositional Systems
Authors: Milliken William J. , Levy Marjorie , Strebelle Sebastien , Zhang Ye 
Published: March 2008

Abstract
The application of reservoir simulation as a tool for reservoir development and management is widespread in the oil and gas industry. Moreover, it is recognized that the results of any reservoir simulation model are strongly influenced by the underlying geologic model. However, the direct relationship between geologic parameters and subsurface flow is obscure. In this paper we explore this relationship in a deepwater depositional system using data from two reservoir analogs: the shallow seismic dataset from the Mahakam Fan and outcrop data from the Brushy Canyon Formation of West Texas.
Shallow seismic data from the Mahakam Fan area shows a high-resolution deepwater channel-levee system consisting of 10 migrating channels. Using an experimental design framework and a series of three increasingly complex models, we investigated the effect of nine different geologic factors on several different measures of the flow behavior. Our results show that, as expected, different geologic factors influence different measures of the flow. Most significant is the clear effect that the proportion and organization of the different internal facies making up the channels have on the recovery factor and net oil production.
The Brushy Canyon outcrops used in this work represent sand-rich proximal deposits of a distributary lobe complex. Here we built models on a very small length scale to investigate the effects of sheet-like reservoir architecture as well as internal facies distribution of the sheets on subsurface flow. Again, an experimental design framework was employed, this time to examine the influence of 11 input variables. The proportion and organization of the internal lobe facies has a significant influence on the subsurface flow here but in these distributary lobe complexes other variables, including the stacking of the lobes, were also found to be important.
The models in this study address flow behavior in deepwater, sparse well environments. Using models from the simple to the complex, we found that several parameters incorporated in the complex models, and not in simple models, had a significant impact on the predicted flow.
Reliability of Multiphase Flowmeters and Test Separators at High Water Cut
Authors: Ojukwu Kelechi Isaac , Edwards John 
Published: March 2008

Abstract
The use of multiphase flowmeters (MPFM) for well test measurements is increasingly becoming a standard practice replacing conventional test separators. These MPFMs are usually tested and calibrated in laboratory controlled flow loops using idealized fluids in steady state conditions. However for high water-cut, high gas-volume-fraction and low pressure unstable flow these controlled conditions are far from reality which can lead to unforeseen errors in the field. Recent experience shows that in certain conditions, the various types of multiphase flowmeters react quite differently to the measurement challenges of transient flows in high water cut and high gas volume fractions (GVF). Some meters can be unreliable in measuring oil rates in certain conditions which leads to inaccurate estimation of the wells' potential and associated uncertainty in plans for production optimization. For example the inaccuracies in measured oil rates could be greater than the gain expected from a stimulation or restoration. An inaccurate measure of oil rate also leads to a poor reconciliation factor and poor estimation of reserves. By resolving these inaccuracies and allocating oil correctly to wells it is possible to invest in right opportunities thereby saving unnecessary expenditure. The factors that affect multiphase flowmeter measurement can range from excessive gas-volume-fraction, low line pressures, solids and unsteady flow.
In 2007 an in-situ comparison was made of two types of multiphase flow meters and two separators to determine the most appropriate well test device for X Field in the Sultanate of Oman. X Field wells are artificially lifted and have a high water cut of 80%. The reconciliation factor (also known as the back allocation factor) before this well test campaign was 0.54. The comparison was made on twelve wells producing to X Field station. Each well was tested for 12 hours in series using an existing inline MPFM, a low pressure production test separator, a second mobile MPFM, a 1440psi separator, and a multiphase tracer technique. The objective to determine the most reliable technique(s) of measuring oil production rates was accomplished, and now the reconciliation factor is 1.03. This paper describes the comparison, how the results were analyzed, and the comparative error associated with each technique.
Quantitative Analysis of Mud Losses in Naturally Fractured Reservoirs: The Effect of Rheology
Authors: Majidi R. , Miska S. Z. , Yu M. , Thompson L. G. 
Published: March 2008

Abstract
Significant fluid loss while drilling through fractured formations is a major problem for drilling operations. From field experience we know that the type and rheological parameters of the drilling fluid have a strong impact upon the rate and volume of losses.
In this work, a mathematical model for flow of Yield-Power-Law (Herschel-Bulkley) fluids in fractures is presented. The governing equation is derived using the principles of conservation of mass and linear momentum for transient radial flow in a fracture. Results are obtained based on numerical solutions and plotted in terms of mud loss volumes versus time for a given drilling fluid under certain operational conditions. Results show how the rheological properties of drilling fluid such as yield stress and flow behavior index ( shear-thinning/thickening effect), influence mud losses in fractured formations. According to this model the yield stress of drilling fluids tremendously decreases the potential for mud losses. The effect of yield stress on reducing mud losses is the same as the effect of overbalance pressure on increasing losses. The shear thinning effect of drilling fluids can also greatly increase the rate of losses. Therefore, mud losses in fractures can be minimized by properly optimizing the rheology of the drilling fluid.
Using this model, quantitative analysis of losses that take into account fluid rheology in order to characterize the fracture can be achieved. One can obtain the hydraulic aperture of conductive fractures by continuously monitoring mud losses and fitting field records of mud losses to the model. For general applications, type-curves are provided that describe drilling fluid loss of Yield-Power-Law fluids into fractures. Newtonian, Bingham Plastic and Power Law fluids are special cases. The proposed model is very useful not only for drilling applications but also for well completion design and fractured reservoir characterization.
Field data measurements are used to demonstrate the practical application of the proposed technique. Good agreement between the model and field data confirms the validity and applicability of the model.
The Study and Application of Fracturing Optimization Technology for Complicated Fault Block Reservoir With Strong Water Sensitivity
Authors: Li Yongming , Guo Jianchun , Yue Yingchun , Zhao Jinzhou , Guo Cunyong 
Published: March 2008

Abstract
S83 reservoir in north China is characterized with abundant faults, strong heterogeneity, medium porosity, medium or low permeability and strong water sensitivity. So its natural production is very low, and hydraulic fracturing is the valid means to enhance production. However, low proppant amount, low average ratio of proppant to fluid, the damage of fracturing fluid and proppant embedment made the previous stimulation effect indistinct. For this reason, we carried on the research into low damage fracturing technology based on the characteristics of S83 reservoir and acquired prominent stimulation effect through field application. This paper presents the research and field application in this reservoir.
Firstly, use reservoir simulation software to optimize fracture parameters of oil wells with or without corresponding water injection wells and to determine fracturing scale. Secondly, do some indoor experiments including rock mechanical test, proppant embedment test and so on, and develop the fracturing fluid with low friction and low damage for S83 reservoir through additive selection. Based on the necessity analysis of enhancing fracture conductivity and combined with the present situation analysis of high conductivity fracturing technology, the low damage fracturing strategy for S83 reservoir is proposed and fracturing design principles of high sand concentration, low fluid amount, fracture length control, strengthening conductivity and low damage are determined. The research results have been used in 2 wells and their postfrac production rose to more than 10m3/d from less than 0.5m3/d before fracturing. The stimulation effect is very prominent. From the results we can conclude that low damage fracturing technology is reasonable and feasible, which presents a new practical fracturing technology for strong water sensitivity formations and has guiding significance for similar reservoirs.
Alteration of Reservoir Diatomites by Hot Water Injection
Authors: Ross C. M. , Ikeda M. , Tang G.-Q. , Kovscek A. R. 
Published: March 2008

Abstract
Pore microstructure and mineral composition of diatomaceous reservoir core were analyzed in concert with core-scale thermal recovery tests. Samples from two diatomaceous oil reservoirs were subjected to spontaneous and forced imbibition coreflood experiments using hot synthetic steam condensate (180°C to 230°C, pH = 10). The effects of these experiments on the rock fabric were determined by comparing mineralogy, pore structure, and physical properties of material collected before and after the experiments. One set of reservoir samples consist of relatively clean, calcite-rich opal-A and opal-CT diatomites. Samples from the other reservoir are clay-rich opal-A diatomites.
The hot alkaline fluids produced porosity channels in samples from both reservoir types. These small channels (10 μm to 2 mm in diameter) form initially at the inlet and grow slowly toward the outlet as experiments progressed. Fines mobilization and perhaps hydraulic action during forced imbibition form the channels. Silica dissolution occurs as shown by ICP analysis of the aqueous effluent; however, signs of pitting and corrosion of diatoms were not observed at magnifications up to 10,000X. The channels improve the homogeneity of the diatomite by penetrating low porosity barriers as shown by the CT-imaged oil saturation profiles with time. As a result of the experiments, permeability may either increase or decrease despite porosity channel formation.
Opal-A to opal-CT conversion did not occur during the experiments as determined by scanning electron microscope imaging and X-ray diffraction analyses. An increase in the amount of mixed layer illite/smectite corresponds with a decrease in plagioclase abundance in the clay-rich diatomite samples. In addition, the grain density decreases in these clay-rich samples due to the preferential dissolution of ferroan dolomite and pyrite. In the calcite-rich samples, grain density increases as the relatively low density silica dissolves leaving the samples enriched with calcite. The increase in grain density is much greater in more soluble, and more calcite-rich, opal-A diatomite samples compared to the less soluble opal-CT diatomites.
Correlation of Cold Production Behavior with Acid/Base Number and Asphaltene Content of Heavy Oil
Authors: Peng J. , Tang G.-Q. , Kovscek A. R. 
Published: March 2008

Abstract
So-called "foamy oil" (heavy-oil solution gas drive) is influenced by a number of factors including chemical and compositional characteristics of the crude oil. Measurements of the concentration of organic acid and base groups as well as asphaltene content of crude oil are combined with data from laboratory-scale heavy-oil solution gas drive. We find that significant asphaltene content as well as substantial acid and base numbers are indicators of whether oil is foamy. The acid number is the amount of potassium hydroxide in mg needed to neutralize the acid groups in 1 g of crude oil, whereas the base number is the amount of potassium hydroxide in mg that is required to neutralize the titrant used in an acid titration of 1g of crude oil. The partitioning of acid and base groups between the asphaltene fraction and deasphalted oil is also studied. Organic acid and base groups are clearly present in the asphaltene fraction. We investigate the lifetime of single foam films of crude-oil and asphaltene solutions. Transparent micromodels etched with a sandstone pore network and containing gas dispersed within the oil are also used to investigate the correlation of acid number, base number, and asphaltene content on gas bubble coalesce. The results show that a high concentration of asphaltene that exhibits acid and base functional groups tends to increase foamability and film life time of gas-crude-oil dispersions. The deasphalted fraction is not foamy despite possessing significant acid and base number. We conclude that acid and base in asphaltene are the source of interfacial properties. Asphaltene content and acid/base number of asphaltene are important factors accounting for the stabilization of dispersed gas bubbles in foamy oil.
Field Practice of Improvement of Waterflooding Effect for a Naturally Fractured Low-Permeability Field
Authors: Pu Hui , Yin Daiyin 
Published: March 2008

Abstract
The naturally fractured reservoirs play an important role in the stable output of Daqing oilfield, which is the largest field in China. But after several years’ development, many wells are becoming to be low efficient wells, the production rate is sharply declining and watercut increased greatly. To improve current development effect, research on how to improve the waterflood effect was carried out, and a pilot test was implemented.
The geological study and the multidisciplinary investigation were first performed. Sourceless microseismic fracture monitoring technique shows that there are natural fractures. The statistics results of sourceless microseismic testing of 36 wells indicate that the total number of fractures is 94, among them, there are 23 east-west fractures, occupying 24.15%, 11 north-east fractures(11.17%), 33 east-west fractures(35.11%), and 27 north-south fractures(28.17%). Also pressure buildup cure shows that there exist inflexion points, which indicates that there are natural fractures. Based on the above research results, integrating detailed reservoir description with reservoir numerical simulation, the injection-production adjustment plan and infill drilling were designed. A field test was carried out: the high watercut wells and low production wells on injection line are converted to injection to form a line drive pattern.
This field test in the Daqing field is an excellent opportunity to: (1) demonstrate the method to improve the development effect of mature naturally fractured reservoir, (2) show that this should be of reference value to improve the development effect of field.